Talos Energy Announces Fourth Quarter and Full Year 2023 Operational and Financial Results
HOUSTON, Feb. 28, 2024 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE:TALO) today announced its operational and financial results for fiscal quarter and full year ended December 31, 2023. Talos also announced its year-end 2023 reserves estimates and the Company's 2024 operational and financial guidance pro forma for the pending QuarterNorth acquisition.
Recent Highlights
- Fourth quarter 2023 production and full year 2023 production, operating expenses, general and administrative expenses, and capital expenditures all in-line or better than guidance.
- First production from Lime Rock and Venice projects was achieved ahead of schedule at rates near the high end of expectations.
- Announced the $1.29 billion acquisition of QuarterNorth Energy Inc. ("QuarterNorth"), which is expected to close in March 2024.
- Refinanced approximately $865 million in 2026 notes, extending maturities to 2029 and 2031 and reducing interest costs on Talos's bonds by 275-300 basis points.
2024 Guidance
- Production between 87.0 and 93.0 thousand barrels of oil equivalent per day ("MBoe/d") (over 70% oil), assuming only nine months of contributions from QuarterNorth. As a reference, actual production from the combined asset base was approximately 99 MBoe/d in the fourth quarter of 2023 and 106 MBoe/d in January 2024.
- Upstream capital expenditures, inclusive of QuarterNorth, of $565 to $595 million, a reduction from Talos standalone 2023 levels.
- Evaluating a full range of strategic alternatives for the Talos Low Carbon Solutions ("TLCS") subsidiary.
- Capital allocation framework focused on material debt reduction and investment in key Upstream projects.
- Based on recent strip pricing, Talos is targeting year-end 2024 leverage of 1.0x or less, including acquisition debt incurred offset by targeted debt paydown of approximately $400 million throughout the year from cash flow generation, excluding any potential proceeds from TLCS.
Talos President and Chief Executive Officer Timothy S. Duncan, stated, "The fourth quarter and early 2024 provided several examples of progress toward our goal of becoming a large-scale offshore exploration and production company. We had a solid operational fourth quarter, delivering 67.7 Mboe/d of oil-weighted production, generating Upstream margins of approximately $42 per barrel of oil equivalent. We brought our Venice and Lime Rock discoveries online ahead of schedule and near the high end of our rate guidance, allowing us to enter 2024 with a strong production rate. Through multiple tactical transactions, we laid the groundwork for inventory expansion, consolidating leases and adding acreage and prospects with high-quality partners. Finally, in January we announced the QuarterNorth acquisition, which should significantly grow our 2024 production, lower our corporate decline rate, expand our inventory, and improve our margins."
Duncan continued, "Following the announcement of the QuarterNorth transaction, we launched several capital markets offerings, which reduced our financing rates and deferred bond maturities to the end of the decade. In 2024, we expect year-over-year production growth of approximately 35%-40%, while capital expenditures are expected to be less than standalone 2023 levels, resulting in material expected free cash flow generation. I am pleased about the trajectory of our business and look forward to an exciting year."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Exploration and Production Updates:
QuarterNorth Acquisition: In January 2024, Talos announced the acquisition of QuarterNorth, a privately-held U.S. Gulf of Mexico exploration and production company. The transaction advances Talos's portfolio with valuable operated infrastructure and oil-weighted deepwater assets that will grow our production and provide attractive future development opportunities. We expect the transaction to enhance Talos's financial performance on key metrics, accelerate deleveraging and improve credit strength. The transaction is currently expected to close in March 2024.
Lime Rock and Venice: Talos successfully started production from the Lime Rock and Venice discoveries in late 2023 ahead of schedule and with early production rates near the high end of expected ranges. Talos expects combined gross recoverable resources of 20-30 MMBoe and owns a 60% working interest in both wells.
Exploration Updates: In December 2023, Talos executed agreements to consolidate acreage across 15 deepwater blocks in the Green Canyon area. The consolidation provides the ability to execute prospective drilling opportunities more efficiently and includes several identified prospects. Talos's participation is expected to be between 15% and 20%. Also in December 2023, Talos was selected as a high bidder on 13 deepwater blocks in the latest federal offshore lease sale. In November 2023, Talos and Repsol S.A. entered into a drilling joint venture covering approximately 400,000 prospective gross acres. The joint venture aims to identify future subsea tie-back prospects in the area using Talos's Neptune facility as the host platform.
Joint Decommissioning Agreement: In February 2024, Talos and Helix Energy Solutions Group, Inc. ("Helix") executed a five-year agreement in which Helix will provide decommissioning services for offshore wells and infrastructure, primarily on the U.S. Gulf of Mexico Shelf. Decommissioning work under the agreement is expected to start in the second quarter 2024.
TLCS Updates:
Seeking Strategic Alternatives: Talos is expanding its capital raise process to include a full range of strategic alternatives for its TLCS subsidiary, and will provide additional updates as available. Talos intends to focus its capital allocation in 2024 on maximizing free cash flow generation net of planned Upstream investments and is primarily focused on debt reduction in the near term.
Other CCS Updates: Bayou Bend CCS LLC commenced drilling an offshore and an onshore stratigraphic well for carbon sequestration in the first quarter 2024. Harvest Bend CCS LLC filed and received administrative completeness status from the EPA for two Class VI permit applications in late 2023.
FOURTH QUARTER AND FULL YEAR 2023 RESULTS
Key Financial Highlights:
($ thousands, except per share amounts) | Three Months Ended December 31, 2023 | Twelve Months Ended December 31, 2023 | ||||
Total revenues | $ | 384,959 | $ | 1,457,886 | ||
Net Income (Loss) | $ | 85,898 | $ | 187,332 | ||
Net Income (Loss) per diluted share | $ | 0.68 | $ | 1.55 | ||
Adjusted Net Income (Loss)* | $ | (960) | $ | 27,887 | ||
Adjusted Net Income (Loss) per diluted share* | $ | (0.01) | $ | 0.23 | ||
Adjusted EBITDA* | $ | 249,115 | $ | 950,718 | ||
Adjusted EBITDA excluding hedges* | $ | 248,098 | $ | 960,175 | ||
Upstream Capital Expenditures | $ | 148,109 | $ | 596,470 | ||
Production
Production for the fourth quarter and full year 2023 was 67.7 MBoe/d (76% oil, 83% liquids), and 66.3 MBoe/d (75% oil, 82% liquids), respectively.
Three Months Ended | Twelve Months Ended | |||||
Oil (MBbl/d) | 51.1 | 49.5 | ||||
Natural Gas (MMcf/d) | 69.8 | 71.8 | ||||
NGL (MBbl/d) | 4.9 | 4.8 | ||||
Total average net daily (MBoe/d) | 67.7 | 66.3 | ||||
Three Months Ended December 31, 2023 | ||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||
Green Canyon Area | 22.3 | 83 | % | 89 | % | 88 | % | |||||
Mississippi Canyon Area | 32.3 | 79 | % | 87 | % | 75 | % | |||||
Shelf and Gulf Coast | 13.1 | 55 | % | 63 | % | 60 | % | |||||
Total average net daily (MBoe/d) | 67.7 | 76 | % | 83 | % | 76 | % | |||||
Twelve Months Ended December 31, 2023 | ||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||
Green Canyon Area | 21.4 | 84 | % | 89 | % | 88 | % | |||||
Mississippi Canyon Area | 31.8 | 79 | % | 87 | % | 71 | % | |||||
Shelf and Gulf Coast | 13.1 | 50 | % | 58 | % | 60 | % | |||||
Total average net daily (MBoe/d) | 66.3 | 75 | % | 82 | % | 74 | % | |||||
Capital Expenditures
Upstream capital expenditures for the fourth quarter and full year 2023, including plugging and abandonment and settled decommissioning obligations, totaled $173.8 million, and $733.7 million respectively.
($ thousands) | Three Months Ended December 31, 2023 | Twelve Months Ended December 31, 2023 | ||||
U.S. drilling & completions | $ | 129,354 | $ | 447,254 | ||
Mexico appraisal & exploration | — | 291 | ||||
Asset management(1) | 2,293 | 83,970 | ||||
Seismic and G&G, land, capitalized G&A and other | 16,462 | 64,955 | ||||
Total Upstream Capital Expenditures | 148,109 | 596,470 | ||||
Plugging & Abandonment and Decommissioning Obligations Settled(2) | 25,687 | 137,199 | ||||
Total Upstream | $ | 173,796 | $ | 733,669 | ||
__________________________________ | |
(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 for the fourth quarter and full year 2023 totaled $9.3 million, and $22.9 million, respectively, which is included in Talos's reported Adjusted EBITDA* figure. CCS capital expenditures for the fourth quarter and full year 2023 totaled $3.8 million, and $41.0 million, respectively, which mainly includes investments in Bayou Bend and funding for general ongoing operations.
($ thousands) | Three Months Ended | Twelve Months Ended | ||||
CCS Expenses | $ | 9,321 | $ | 22,883 | ||
CCS Capital Expenditures | 3,778 | 40,961 | ||||
Total CCS Costs Incurred | $ | 13,099 | $ | 63,844 | ||
Liquidity and Leverage
At December 31, 2023, Talos had approximately $787.9 million of liquidity, with $765.0 million undrawn on its credit facility and approximately $33.6 million in cash, less approximately $10.8 million in outstanding letters of credit. On December 31, 2023, Talos had $1,066.0 million in total debt. Net Debt* was $1,032.4 million. Net Debt to Pro Forma Last Twelve Months ("LTM") Adjusted EBITDA* was 1.0x, inclusive of EnVen pre-closing contributions to Adjusted EBITDA in early 2023, as permitted by the terms of our Bank Credit Facility.
($ thousands) | December 31, 2023 | |||
Bank Credit Facility-matures March 2027 | $ | 200,000 | ||
12.00% Second-Priority Senior Secured Notes -- due January 2026 | 638,541 | |||
11.75% Senior Secured Second Lien Notes -- due April 2026 | 227,500 | |||
Total Debt | 1,066,041 | |||
Less: Cash and cash equivalents | (33,637) | |||
Net Debt | $ | 1,032,404 | ||
On February 7, 2024, Talos completed an upsized debt offering of $1,250.0 million in aggregate principal amount of Second-Priority Senior Secured Notes, consisting of $625.0 million of 9.000% Second-Priority Senior Secured Notes due 2029 and $625.0 million of 9.375% Second-Priority Senior Secured Notes due 2031. Talos used the net proceeds from the debt offering to fund the redemption of all of the outstanding 12.00% Second-Priority Senior Secured Notes due January 2026 and the 11.75% Senior Secured Second Lien Notes due April 2026.
The following table summarizes Talos's bonds outstanding as of December 31, 2023 and pro forma for the refinancing subsequent to year-end 2023.
($ thousands) | December 31, 2023 | Pro Forma for | |||||
12.00% Second-Priority Senior Secured Notes -- due January 2026 | $ | 638,541 | $ | - | |||
11.75% Senior Secured Second Lien Notes -- due April 2026 | 227,500 | - | |||||
New 9.000% Second-Priority Senior Secured Notes -- due February 2029 | - | 625,000 | |||||
New 9.375% Second-Priority Senior Secured Notes -- due February 2031 | - | 625,000 | |||||
Total Second Lien Notes | $ | 866,041 | $ | 1,250,000 | |||
Footnotes:
*See "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures.
HISTORICAL AND PRO FORMA YEAR-END 2023 RESERVES
SEC Reserves
As of December 31, 2023, Talos had proved reserves of 152.8 MMBoe and, on a pro forma basis, including assets expected to be acquired from QuarterNorth, would have had proved reserves of 215.8 MMBoe. The Standardized Measure of Talos's standalone reserves was approximately $3.0 billion and the PV-10 of Talos proved reserves was approximately $3.5 billion. The PV-10 of pro forma proved reserves was approximately $5.1 billion. Talos's reserves and Talos's QuarterNorth figures are prepared by Talos management and audited by Netherland Sewell & Associates ("NSAI"). All figures are fully burdened by and net of all plugging and abandonment costs associated with the properties included in the reserves report. The following tables summarize proved reserves at December 31, 2023 based on SEC pricing of $78.21 per barrel of oil and $2.64 per MMBtu of natural gas. The acquisition of QuarterNorth is currently expected to close in March 2024.
In addition to proved reserves, Talos's audited probable reserves were 87.4 MMBoe and pro forma audited probable reserves were 148.4 MMBoe with a corresponding PV-10 of approximately $2.5 billion and $3.9 billion, respectively.
Pro Forma SEC Reserves as of December 31, 2023(1)(2)(3) | ||||||||||||
MBoe | % of Total | % Oil | PV -10 | |||||||||
Proved Developed Producing | 128,674 | 60 | % | 76 | % | $ | 4,214,100 | |||||
Proved Developed Non-Producing | 42,661 | 20 | % | 65 | % | 438,256 | ||||||
Total Proved Developed | 171,335 | 79 | % | 73 | % | 4,652,356 | ||||||
Proved Undeveloped | 44,442 | 21 | % | 62 | % | 441,992 | ||||||
Total Proved | 215,778 | 100 | % | 71 | % | $ | 5,094,348 | |||||
Reserves Sensitivities
The following tables summarize the PV-10 values of Talos's proved reserves at December 31, 2023, at various crude oil prices and a flat $3.50 per MMBtu gas price, except as noted below, inclusive of QuarterNorth.
Pro Forma Year-End 2023 Reserves Sensitivity (PV-10) ($000)(4) | |||||||||||||||
$65 | $75 | SEC(2) | $85 | $95 | |||||||||||
Proved Developed Producing | $ | 3,300,092 | $ | 4,078,540 | $ | 4,214,100 | $ | 4,866,048 | $ | 5,653,819 | |||||
Proved Developed Non-Producing | 193,174 | 401,457 | 438,256 | 608,591 | 804,670 | ||||||||||
Total Proved Developed | 3,493,266 | 4,479,997 | 4,652,356 | 5,474,640 | 6,458,489 | ||||||||||
Proved Undeveloped | 261,985 | 429,085 | 441,992 | 601,967 | 777,635 | ||||||||||
Total Proved | $ | 3,755,252 | $ | 4,909,082 | $ | 5,094,348 | $ | 6,076,607 | $ | 7,236,124 | |||||
(1) | This table summarizes year end 2023 reserves of Talos and QuarterNorth collectively. The acquisition of QuarterNorth cannot be guaranteed. In the event the QuarterNorth acquisition is not completed, the reserve volumes and associated figures presented above would be materially reduced. |
(2) | Reserves figures are presented inclusive of the plugging and abandonment obligations and before hedges, utilizing SEC pricing of $78.21 per barrel of oil and $2.64 per MMBtu of natural gas. |
(3) | PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our stand-alone proved reserves to the corresponding standardized measure of discounted future net cash flows at December 31, 2023. With respect to the pro forma PV-10 giving effect to our pending acquisition, we are unable to reconcile to Standardized Measure without unreasonable efforts. Similarly, PV-10 cannot be reconciled to Standardized Measure for prices other than SEC pricing, because GAAP does not prescribe any corresponding measure based on other pricing, and accordingly it is not practicable to prepare any such reconciliation. |
(4) | Pro forma sensitivities are based on Talos and QuarterNorth SEC reserves databases as of December 31, 2023. Reserves volumes may fluctuate slightly based on economic limitations. |
2024 OPERATIONAL & FINANCIAL GUIDANCE
Talos intends to prioritize significant free cash flow generation and the advancement of key Upstream projects expected to drive future shareholder value creation in its 2024 operational and financial plan, in addition to the integration of QuarterNorth. Talos expects its level of capital investments in 2024, inclusive of QuarterNorth, to be less than Talos standalone 2023 levels. This is expected to result in an attractive reinvestment rate of 45%-50% (excluding plugging and abandonment) and material cash flow generation. Talos is targeting total debt reduction of approximately $400 million and to end 2024 with a leverage ratio of 1.0x or less, inclusive of acquisition debt incurred offset by debt paydown.
Talos's 2024 production guidance includes known and expected deductions from baseline production of the assets, including 1) only nine assumed months of QuarterNorth contributions (versus twelve months pro forma), 2) expected planned downtime for facility and downstream maintenance, including the Helix Producer I ("HP-I") drydock and Katmai shut-in, among others, and 3) expected but unplanned downtime for risking and weather-related events.
For the first quarter 2024, Talos expects average daily production of 70.0 - 72.0 MBoe/d, which includes the impact of the planned HP-1 dry-dock shut-in in March 2024 and does not include any contributions from QuarterNorth. Talos's actual January 2024 standalone production was approximately 73.5 MBoe/d, and preliminary standalone February 2024 production was approximately 75.0 MBoe/d.
The following summarizes key elements of Talos's 2024 production guidance.
FY 2024 | |||||||
Low | High | ||||||
Pro Forma Estimate Before Known & Estimated Unplanned Reductions | 105.0 | 110.0 | |||||
Less: QuarterNorth Partial Year Contribution | (8.3) | (8.0) | |||||
Less: Planned Downtime Impacts | (5.8) | (5.5) | |||||
Less: Weather and Unplanned Downtime Risking | (4.0) | (3.5) | |||||
Net Risked Production Estimate (MBoe/d) | 87.0 | 93.0 | |||||
Note: Figures may not sum due to rounding. | |||||||
Cash operating expenses include a full twelve month impact of EnVen, as compared to approximately ten and a half months in 2023, and nine assumed months of QuarterNorth as well as approximately $15 million related to the HP-1 drydock and other associated maintenance. This guidance also includes the execution of multiple deepwater workover projects that will increase and/or reinstate production. The following summarizes Talos's full year 2024 operational and financial guidance.
For more information, please refer to the Fourth Quarter 2023 Earnings Presentation available under Presentations and Filings on the Investor Relations section of Talos's website.
FY 2024 | |||||||
($ Millions, unless highlighted): | Low | High | |||||
Production | Oil (MMBbl) | 23.0 | 24.0 | ||||
Natural Gas (Mcf) | 38.0 | 44.0 | |||||
NGL (MMBbl) | 2.5 | 2.7 | |||||
Total Production (MMBoe) | 31.8 | 34.0 | |||||
Avg Daily Production (MBoe/d) | 87.0 | 93.0 | |||||
Cash Expenses | Cash Operating Expenses(1)(2)(4)* | $ | 505 | $ | 525 | ||
Workovers | $ | 45 | $ | 55 | |||
G&A(2)(3)* | $ | 100 | $ | 110 | |||
Capex | Upstream Capital Expenditures(5) | $ | 565 | $ | 595 | ||
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. |
(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 February 28, 2024. The table includes Talos volumes only and does not include any associated 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) | |||||||||||
January - March 2024 | Fixed Swaps | 19,363 | $ | 74.06 | --- | --- | --- | |||||||||
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 | 25,500 | $ | 74.06 | --- | --- | --- | |||||||||
April - June 2024 | Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | ||||||||
July - September 2024 | Fixed Swaps | 17,000 | $ | 75.40 | --- | --- | --- | |||||||||
July - September 2024 | Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | ||||||||
October - December 2024 | Fixed Swaps | 19,000 | $ | 74.46 | --- | --- | --- | |||||||||
October - December 2024 | Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | ||||||||
January - March 2025 | Fixed Swaps | 10,000 | $ | 71.97 | --- | --- | --- | |||||||||
April - June 2025 | Fixed Swaps | 9,000 | $ | 73.81 | --- | --- | --- | |||||||||
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) | |||||||||||
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 | 15,000 | $ | 3.35 | --- | --- | --- | |||||||||
October - December 2024 | Collar | 10,000 | --- | --- | $ | 4.00 | $ | 6.90 | ||||||||
January - March 2025 | Fixed Swaps | 20,000 | $ | 4.14 | --- | --- | --- | |||||||||
April - June 2025 | Fixed Swaps | 15,000 | $ | 3.63 | --- | --- | --- | |||||||||
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 Thursday, February 29, 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 (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 March 7, 2024 and can be accessed by dialing (877) 344-7529 and using access code 2924676. For more information, please refer to the Fourth Quarter 2023 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 safely and efficiently maximizing long-term value through its Upstream Exploration & Production and Low Carbon Solutions businesses. We currently operate in the United States 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
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 believe, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: risks related to the pending and future mergers and acquisitions, such as the acquisition of QuarterNorth Energy Inc. ("QuarterNorth," and such transaction, the "QuarterNorth Acquisition"), including the risk that we may fail to complete such transaction on the terms contemplated or at all, and/or to realize the expected benefits of any such transaction; business strategy; recoverable resources, reserves and prospective storage resources; 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; timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling and low carbon solutions plans, including potential strategic alternatives; availability of pipeline connections on economic terms; competition, government regulations 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 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 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; the success of our low carbon solutions business, including as a result of any development opportunities, permitting, 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 in our low carbon solutions 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. 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; risks associated with permitting for—and access to capital to finance—our CCS opportunities;; and the other risks discussed in "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2023 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 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. Certain reserve estimates herein were prepared based on specified management price parameters as indicated herein. These specified prices reflect what we believe to be reasonable assumptions as to average future commodity prices over the productive lives of our properties and those to be acquired from QuarterNorth. However, we caution you that the pricing used is not a projection of future oil and natural gas prices, and should be carefully considered in addition to, and not as a substitute for, SEC prices, when considering our oil, natural gas and NGL reserves.
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, PV-10, LTM Adjusted EBITDA, Pro Forma LTM Adjusted EBITDA, Net Debt, Net Debt/LTM Adjusted EBITDA, Net Debt/Pro Forma LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage. 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) | ||||||
Year Ended December 31, | ||||||
2023 | 2022 | |||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 33,637 | $ | 44,145 | ||
Accounts receivable: | ||||||
Trade, net | 178,977 | 150,598 | ||||
Joint interest, net | 79,337 | 54,697 | ||||
Other, net | 19,296 | 6,684 | ||||
Assets from price risk management activities | 36,152 | 25,029 | ||||
Prepaid assets | 64,387 | 84,759 | ||||
Other current assets | 10,389 | 1,917 | ||||
Total current assets | 422,175 | 367,829 | ||||
Property and equipment: | ||||||
Proved properties | 7,906,295 | 5,964,340 | ||||
Unproved properties, not subject to amortization | 268,315 | 154,783 | ||||
Other property and equipment | 34,027 | 30,691 | ||||
Total property and equipment | 8,208,637 | 6,149,814 | ||||
Accumulated depreciation, depletion and amortization | (4,168,328) | (3,506,539) | ||||
Total property and equipment, net | 4,040,309 | 2,643,275 | ||||
Other long-term assets: | ||||||
Restricted cash | 102,362 | — | ||||
Assets from price risk management activities | 17,551 | 7,854 | ||||
Equity method investments | 146,049 | 1,745 | ||||
Other well equipment | 54,277 | 25,541 | ||||
Notes receivable, net | 16,207 | — | ||||
Operating lease assets | 11,418 | 5,903 | ||||
Other assets | 5,961 | 6,479 | ||||
Total assets | $ | 4,816,309 | $ | 3,058,626 | ||
LIABILITIES AND STOCKHOLDERSʼ EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 84,193 | $ | 128,174 | ||
Accrued liabilities | 227,690 | 219,769 | ||||
Accrued royalties | 55,051 | 52,215 | ||||
Current portion of long-term debt | 33,060 | — | ||||
Current portion of asset retirement obligations | 77,581 | 39,888 | ||||
Liabilities from price risk management activities | 7,305 | 68,370 | ||||
Accrued interest payable | 42,300 | 36,340 | ||||
Current portion of operating lease liabilities | 2,666 | 1,943 | ||||
Other current liabilities | 48,769 | 60,359 | ||||
Total current liabilities | 578,615 | 607,058 | ||||
Long-term liabilities: | ||||||
Long-term debt | 992,614 | 585,340 | ||||
Asset retirement obligations | 819,645 | 501,773 | ||||
Liabilities from price risk management activities | 795 | 7,872 | ||||
Operating lease liabilities | 18,211 | 14,855 | ||||
Other long-term liabilities | 251,278 | 176,152 | ||||
Total liabilities | 2,661,158 | 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 December 31, 2023 and 2022, respectively | — | — | ||||
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively | 1,275 | 826 | ||||
Additional paid-in capital | 2,549,097 | 1,699,799 | ||||
Accumulated deficit | (347,717) | (535,049) | ||||
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively | (47,504) | — | ||||
Total stockholdersʼ equity | 2,155,151 | 1,165,576 | ||||
Total liabilities and stockholdersʼ equity | $ | 4,816,309 | $ | 3,058,626 | ||
Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per share amounts) | ||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||
Revenues: | ||||||||||||
Oil | $ | 362,651 | $ | 286,348 | $ | 1,357,732 | $ | 1,365,148 | ||||
Natural gas | 14,651 | 45,559 | 68,034 | 227,306 | ||||||||
NGL | 7,657 | 10,294 | 32,120 | 59,526 | ||||||||
Total revenues | 384,959 | 342,201 | 1,457,886 | 1,651,980 | ||||||||
Operating expenses: | ||||||||||||
Lease operating expense | 103,546 | 78,936 | 389,621 | 308,092 | ||||||||
Production taxes | 638 | 818 | 2,451 | 3,488 | ||||||||
Depreciation, depletion and amortization | 183,058 | 119,456 | 663,534 | 414,630 | ||||||||
Accretion expense | 22,722 | 13,595 | 86,152 | 55,995 | ||||||||
General and administrative expense | 37,236 | 29,012 | 158,493 | 99,754 | ||||||||
Other operating (income) expense | 3,017 | 21,760 | (52,155) | 33,902 | ||||||||
Total operating expenses | 350,217 | 263,577 | 1,248,096 | 915,861 | ||||||||
Operating income (expense) | 34,742 | 78,624 | 209,790 | 736,119 | ||||||||
Interest expense | (44,295) | (33,967) | (173,145) | (125,498) | ||||||||
Price risk management activities income (expense) | 94,596 | (41,058) | 80,928 | (272,191) | ||||||||
Equity method investment income (expense) | (6,147) | (377) | (3,209) | 14,222 | ||||||||
Other income (expense) | 1,921 | (191) | 12,371 | 31,800 | ||||||||
Net income (loss) before income taxes | 80,817 | 3,031 | 126,735 | 384,452 | ||||||||
Income tax benefit (expense) | 5,081 | (281) | 60,597 | (2,537) | ||||||||
Net income (loss) | $ | 85,898 | $ | 2,750 | $ | 187,332 | $ | 381,915 | ||||
Net income (loss) per common share: | ||||||||||||
Basic | $ | 0.69 | $ | 0.03 | $ | 1.56 | $ | 4.63 | ||||
Diluted | $ | 0.69 | $ | 0.03 | $ | 1.55 | $ | 4.56 | ||||
Weighted average common shares outstanding: | ||||||||||||
Basic | 124,150 | 82,597 | 119,894 | 82,454 | ||||||||
Diluted | 125,173 | 84,418 | 120,752 | 83,683 | ||||||||
Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) | |||||||||
Year Ended December 31, | |||||||||
2023 | 2022 | 2021 | |||||||
Cash flows from operating activities: | |||||||||
Net income (loss) | $ | 187,332 | $ | 381,915 | $ | (182,952) | |||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | |||||||||
Depreciation, depletion, amortization and accretion expense | 749,686 | 470,625 | 454,123 | ||||||
Write-down of oil and natural gas properties and other well equipment | — | — | 23,729 | ||||||
Amortization of discount, premium and deferred financing costs | 15,039 | 14,379 | 13,382 | ||||||
Equity-based compensation expense | 12,953 | 15,953 | 10,992 | ||||||
Price risk management activities (income) expense | (80,928) | 272,191 | 419,077 | ||||||
Net cash received (paid) on settled derivative instruments | (9,457) | (425,559) | (290,164) | ||||||
Equity method investment (income) expense | 3,209 | (14,222) | — | ||||||
Loss (gain) on extinguishment of debt | — | 1,569 | 13,225 | ||||||
Settlement of asset retirement obligations | (86,615) | (69,596) | (67,988) | ||||||
Gain (loss) on sale of assets | (66,115) | 303 | (687) | ||||||
Changes in operating assets and liabilities: | |||||||||
Accounts receivable | 20,352 | 14,927 | (35,396) | ||||||
Other current assets | 7,066 | (36,545) | (18,901) | ||||||
Accounts payable | (60,401) | 24,258 | (6,261) | ||||||
Other current liabilities | (96,960) | 73,531 | 64,800 | ||||||
Other non-current assets and liabilities, net | (76,092) | (13,990) | 14,409 | ||||||
Net cash provided by (used in) operating activities | 519,069 | 709,739 | 411,388 | ||||||
Cash flows from investing activities: | |||||||||
Exploration, development and other capital expenditures | (561,434) | (323,164) | (293,331) | ||||||
Proceeds from (cash paid for) acquisitions, net of cash acquired | 17,617 | (3,500) | (5,399) | ||||||
Proceeds from (cash paid for) sale of property and equipment, net | 73,004 | 1,937 | 4,983 | ||||||
Contributions to equity method investees | (29,447) | (2,250) | — | ||||||
Investment in intangible assets | (12,366) | — | — | ||||||
Proceeds from sale of equity method investment | — | 15,000 | — | ||||||
Net cash provided by (used in) investing activities | (512,626) | (311,977) | (293,747) | ||||||
Cash flows from financing activities: | |||||||||
Issuance of senior notes | — | — | 600,500 | ||||||
Redemption of senior notes | (30,000) | (18,184) | (356,803) | ||||||
Proceeds from Bank Credit Facility | 825,000 | 85,000 | 100,000 | ||||||
Repayment of Bank Credit Facility | (625,000) | (460,000) | (365,000) | ||||||
Deferred financing costs | (11,775) | (189) | (27,833) | ||||||
Other deferred payments | (1,545) | — | (7,921) | ||||||
Payments of finance lease | (16,306) | (25,493) | (21,804) | ||||||
Purchase of treasury stock | (47,504) | — | — | ||||||
Employee stock awards tax withholdings | (7,459) | (4,603) | (3,161) | ||||||
Net cash provided by (used in) financing activities | 85,411 | (423,469) | (82,022) | ||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | 91,854 | (25,707) | 35,619 | ||||||
Cash, cash equivalents and restricted cash: | |||||||||
Balance, beginning of period | 44,145 | 69,852 | 34,233 | ||||||
Balance, end of period | $ | 135,999 | $ | 44,145 | $ | 69,852 | |||
Supplemental non-cash transactions: | |||||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 114,972 | $ | 105,773 | $ | 45,761 | |||
Supplemental cash flow information: | |||||||||
Interest paid, net of amounts capitalized | $ | 130,313 | $ | 91,809 | $ | 68,891 | |||
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 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, $/Boe and percentage data):
($ thousands) | Three Months Ended | Twelve Months Ended | ||||
Reconciliation of Net Income (Loss) to Adjusted EBITDA: | ||||||
Net Income (loss) | $ | 85,898 | $ | 187,332 | ||
Interest expense | 44,295 | 173,145 | ||||
Income tax expense (benefit) | (5,081) | (60,597) | ||||
Depreciation, depletion and amortization | 183,058 | 663,534 | ||||
Accretion expense | 22,722 | 86,152 | ||||
EBITDA | 330,892 | 1,049,566 | ||||
Transaction and other (income) expenses(1) | 5,504 | (33,295) | ||||
Decommissioning obligations(2) | 2,425 | 11,879 | ||||
Derivative fair value (gain) loss(3) | (94,596) | (80,928) | ||||
Net cash received (paid) on settled derivative instruments(3) | 1,017 | (9,457) | ||||
Non-cash equity-based compensation expense | 3,873 | 12,953 | ||||
Adjusted EBITDA | 249,115 | 950,718 | ||||
Add: Net cash (received) paid on settled derivative instruments(3) | (1,017) | 9,457 | ||||
Adjusted EBITDA excluding hedges | $ | 248,098 | $ | 960,175 | ||
_________________________________ | |
(1) | Transaction expenses includes $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses for the twelve months ended December 31, 2023, respectively. 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 twelve months ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the twelve months ended December 31, 2023. |
(2) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in "Other operating (income) expense" on our consolidated statements of operations. |
(3) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
($ thousands, except per BOE amounts) | Three Months Ended | Twelve Months Ended | ||||
Reconciliation of Adjusted EBITDA to Upstream Adjusted EBITDA: | ||||||
Adjusted EBITDA | $ | 249,115 | $ | 950,718 | ||
CCS and Corporate Unallocated Costs: | ||||||
Equity method investment loss | 5,894 | 3,329 | ||||
General and administrative expense | 6,519 | 19,466 | ||||
Other operating expense | (93) | 300 | ||||
Other income | (6) | (5,069) | ||||
Transaction and other income (expenses)(1) | (336) | 13,142 | ||||
Non-cash equity-based compensation expense | (690) | (2,157) | ||||
Upstream Adjusted EBITDA | 260,403 | 979,729 | ||||
Add: Net cash paid on settled derivative instruments(2) | (1,017) | 9,457 | ||||
Upstream Adjusted EBITDA excluding hedges | $ | 259,386 | $ | 989,186 | ||
Production: | ||||||
Boe(3) | 6,224 | 24,195 | ||||
Upstream Adjusted EBITDA margin and Upstream Adjusted EBITDA excl hedges margin: | ||||||
Upstream Adjusted EBITDA per Boe(3) | $ | 41.84 | $ | 40.49 | ||
Upstream Adjusted EBITDA excl hedges per Boe(2)(3) | $ | 41.68 | $ | 40.88 | ||
______________________________________ | |
(1) | 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. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the twelve months ended December 31, 2023. |
(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 | Twelve Months Ended | ||||
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital): | ||||||
Adjusted EBITDA | $ | 249,115 | $ | 950,718 | ||
Upstream capital expenditures | (148,109) | (596,470) | ||||
Plugging & abandonment | (15,518) | (86,615) | ||||
Decommissioning obligations settled | (10,169) | (50,584) | ||||
CCS capital expenditures | (3,778) | (40,961) | ||||
Interest expense | (44,295) | (173,145) | ||||
Adjusted Free Cash Flow (before changes in working capital) | $ | 27,246 | $ | 2,943 | ||
($ thousands) | Three Months Ended December 31, 2023 | Twelve Months Ended December 31, 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) | $ | 176,258 | $ | 519,069 | ||
(Increase) decrease in operating assets and liabilities | 20,135 | 206,035 | ||||
Upstream capital expenditures(2) | (148,109) | (596,470) | ||||
Decommissioning obligations settled | (10,169) | (50,584) | ||||
CCS capital expenditures | (3,778) | (40,961) | ||||
Transaction and other (income) expenses(3) | 5,817 | 41,786 | ||||
Decommissioning obligations(4) | 2,425 | 11,879 | ||||
Amortization of deferred financing costs and original issue discount | (3,792) | (15,039) | ||||
Income tax benefit | (5,081) | (60,597) | ||||
Other adjustments | (6,460) | (12,175) | ||||
Adjusted Free Cash Flow (before changes in working capital) | $ | 27,246 | $ | 2,943 | ||
______________________________ | |
(1) | Includes settlement of asset retirement obligations. |
(2) | Includes accruals and excludes acquisitions. |
(3) | Transaction expenses includes $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses for the twelve months ended December 31, 2023, respectively. 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 twelve months ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the twelve months ended December 31, 2023. |
(4) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.
Three Months Ended December 31, 2023 | Twelve Months Ended December 31, 2023 | |||||||||||||||||
($ thousands, except per share amounts) | Basic per | Diluted per | Basic per | Diluted per | ||||||||||||||
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss): | ||||||||||||||||||
Net Income (loss) | $ | 85,898 | $ | 0.69 | $ | 0.68 | $ | 187,332 | $ | 1.56 | $ | 1.55 | ||||||
Transaction and other (income) expenses(1) | 5,504 | $ | 0.04 | $ | 0.04 | (33,295) | $ | (0.28) | $ | (0.28) | ||||||||
Decommissioning obligations(2) | 2,425 | $ | 0.02 | $ | 0.02 | 11,879 | $ | 0.10 | $ | 0.10 | ||||||||
Derivative fair value loss(3) | (94,596) | $ | (0.76) | $ | (0.75) | (80,928) | $ | (0.67) | $ | (0.67) | ||||||||
Net cash received on paid derivative instruments(3) | 1,017 | $ | 0.01 | $ | 0.01 | (9,457) | $ | (0.08) | $ | (0.08) | ||||||||
Non-cash income tax benefit | (5,081) | $ | (0.04) | $ | (0.04) | (60,597) | $ | (0.51) | $ | (0.50) | ||||||||
Non-cash equity-based compensation expense | 3,873 | $ | 0.03 | $ | 0.03 | 12,953 | $ | 0.11 | $ | 0.11 | ||||||||
Adjusted Net Income (Loss)(4) | $ | (960) | $ | (0.01) | $ | (0.01) | $ | 27,887 | $ | 0.23 | $ | 0.23 | ||||||
Weighted average common shares outstanding at December 31, 2023: | ||||||||||||||||||
Basic | 124,150 | 119,894 | ||||||||||||||||
Diluted | 126,196 | 120,752 | ||||||||||||||||
___________________________________ | |
(1) | Transaction expenses includes $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses for the twelve months ended December 31, 2023, respectively. 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 twelve months ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the twelve months ended December 31, 2023. |
(2) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
(3) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. |
(4) | The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, and Net Debt to LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies.
Net Debt. Total Debt principal minus cash and cash equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
($ thousands) | December 31, 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 | 227,500 | ||
Bank Credit Facility – matures March 2027 | 200,000 | ||
Total Debt | 1,066,041 | ||
Less: Cash and cash equivalents | (33,637) | ||
Net Debt | $ | 1,032,404 | |
LTM Adjusted EBITDA | $ | 950,718 | |
LTM Adjusted EBITDA from Acquired Assets (from January 1, 2023 to February 13, 2023) | 33,120 | ||
Pro Forma LTM Adjusted EBITDA | $ | 983,838 | |
Reconciliation of Net Debt to Pro Forma LTM Adjusted EBITDA: | |||
Net Debt / Pro Forma LTM Adjusted EBITDA(1) | 1.0x | ||
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(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. |
Reconciliation of PV-10 to Standardized Measure
Reconciliation of PV-10 to Standardized Measure PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the Company's properties. Talos and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies' properties without regard to the specific tax characteristics of such entities. PV-10 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
The table below presents the reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves:
($ thousands) | Year Ended December 31, 2023 | ||
Standardized measure (1)(2) | $ | 3,043,488 | |
Present value of future income taxes discounted at 10% | 455,330 | ||
PV-10 (Non-GAAP) | $ | 3,498,818 | |
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(1) | All estimated future costs to settle asset retirement obligations associated with our proved reserves have been included in our calculation of the standardized measure for the period presented. |
(2) | Standardized measure is based on management estimates and is not audited by third party reserve engineers. |
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SOURCE Talos Energy