Talos Energy Announces First Quarter 2024 Operational and Financial Results
HOUSTON, May 6, 2024 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for fiscal quarter ended March 31, 2024. Talos also provided second quarter 2024 production guidance and reiterated its operational and financial guidance for the full year 2024.
Key Highlights
- Production of 79.6 thousand barrels of oil equivalent per day ("MBoe/d") (71% oil, 80% liquids) is at the high end of Talos's first quarter 2024 guidance range.
- Closed QuarterNorth Energy Inc. ("QuarterNorth") acquisition earlier than expected and progressing integration activities as planned.
- Completed the sale of Talos Low Carbon Solutions LLC ("TLCS") to TotalEnergies E&P USA, Inc. ("TotalEnergies") for approximately $148 million, which included Talos's entire Carbon Capture & Sequestration ("CCS") business.
- Achieved run-rate synergies from QuarterNorth acquisition and the TLCS sale of approximately $20 million in the first two months.
- Reduced debt by $225 million since closing the QuarterNorth acquisition, achieving a leverage ratio of 1.0x ahead of schedule.
- Refinanced approximately $865 million in 2026 notes, extending maturities and reducing interest rates on Talos's bonds by 275-300 basis points.
- Awarded 17 deepwater blocks comprising 95,000 gross acres in the U.S. Gulf of Mexico Outer Continental Shelf Federal Lease Sale 261.
- Sustained combined gross production rates of over 18 MBoe/d from the Venice and Lime Rock fields since starting production ahead of schedule in late December 2023.
First Quarter Summary
- Revenue of $429.9 million, driven by realized prices (excluding hedges) of $76.01 per barrel for oil, $20.59 per barrel for natural gas liquids ("NGLs"), and $2.74 per thousand cubic feet ("Mcf") for natural gas.
- Net Loss of $112.4 million, or $0.71 Net Loss per diluted share, and Adjusted Net Loss* of $20.9 million, or $0.13 Adjusted Net Loss per diluted share*, excluding CCS investments.
- Adjusted EBITDA* of $267.5 million, excluding CCS investments.
- Upstream capital expenditures of $112.4 million.
- Net cash provided by operating activities of $96.4 million.
- Adjusted Free Cash Flow* of $77.7 million, excluding CCS investments and TLCS sale proceeds.
Talos President and Chief Executive Officer Tim Duncan stated, "Talos had an extremely active first quarter and achieved solid execution across our business with production near the high end of our guidance range, representing record volumes. After completing two important transactions, we further repositioned the Company with capital market transactions that strengthened our credit profile. Our QuarterNorth acquisition, which closed one month earlier than scheduled, adds scale and high-margin oil-weighted production to our portfolio and is expected to generate sustainable free cash flow. I'm also very proud of the Talos team for their intense focus and dedication as the integration progresses smoothly and we work to realize the expected synergies by year-end 2024. We signed and concurrently closed the sale of TLCS, crystallizing a 2x multiple of invested capital for our shareholders. We used the proceeds to immediately repay borrowings under our credit facility. By the end of the first quarter, we repaid over $225 million in borrowings and ended the quarter with a leverage ratio of 1.0x, earlier than anticipated.
"Talos's drilling program is underway, balancing a mix of low-risk and high-impact projects that could provide a material increase to our reserves. Projects for the second half of 2024 are in final preparations to execute upon rig delivery, including further appraisal of the Katmai discovery and drilling the high-impact Daenerys prospect. We remain focused on our strategic priorities to generate substantial free cash flow and have increased our total debt reduction target from $400 million to approximately $550 million in 2024."
Footnotes:
*See "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures.
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
QuarterNorth Acquisition: On March 4, 2024, Talos closed the previously announced acquisition of QuarterNorth. We expect the strategic transaction of oil-weighted deepwater assets and related infrastructure to enhance Talos's ability to consistently generate substantial free cash flow while expanding its portfolio of growth opportunities. Integration is on track as Talos works to realize the expected synergies from the combination by year-end 2024. Talos's full year 2024 operational and financial guidance includes ten months of contributions from the acquired assets.
TLCS Divestiture: On March 18, 2024, Talos signed and completed the sale of TLCS to TotalEnergies for approximately $148 million, including the retention of $6 million of related cash, realizing approximately a 2.0x multiple on invested capital and an internal rate of return exceeding 100%. Talos used the proceeds from the sale to immediately repay borrowings under its Credit Facility. Talos may realize additional future cash payments upon achievement of certain milestones at the Harvest Bend or Coastal Bend projects or upon a subsequent sale of these projects by TotalEnergies.
Outer Continental Shelf Federal Lease Sale 261: Talos acquired 17 leases covering 95,000 gross acres, with 12-15 potential drilling locations already identified on that acreage. Most locations are near existing Talos infrastructure, allowing for tie-back to Company facilities.
Capital Markets Transactions: In January 2024, Talos issued $1,250 million in second lien notes, which were used to refinance approximately $865 million in 2026 second lien notes, extending maturities to the end of the decade and reducing interest rates on Talos's bonds by 275-300 basis points. In addition, Talos closed an underwritten public offering of Talos's common stock with net proceeds of approximately $388.0 million, which was used to fund the QuarterNorth transaction.
Exploration and Production Updates:
Katmai: Talos expects to commence drilling the Katmai West #2 well in the third quarter of 2024 to further appraise the field, potentially adding significant reserves. First quarter 2025 modifications to the host facility, Tarantula, will increase capacity from 27 MBoe/d to 35 MBoe/d, which will be constrained relative to the full rate capacity of the Katmai wells, allowing for extended flat production. Talos will hold a 50% working interest in Katmai. Talos is the 100% owner and operator of the Tarantula facility.
Daenerys: Talos expects to drill the Daenerys exploration well, a high-impact subsalt project, that will evaluate the Miocene section and carries a gross unrisked recoverable resource potential between 100 – 300 MMBoe. Talos has a 30% working interest in the initial test well. The prospect is part of a broader farm-in transaction that was executed in 2023 with a combined approximately 23,000 gross acres in the Walker Ridge area.
Lobster: Talos successfully drilled through the BUL-1 and Tex-Mex-E sand in the Lobster Field in the first quarter of 2024. The well is being completed as a waterflood (down-hole water injection) well and is expected to increase the hydrocarbon recovery of the existing producing wells in the prolific BUL-1 field pay. Production is expected to increase by over 2 MBoe/d gross in the next 12-18 months. Talos owns a 67% working interest.
Claiborne: The Claiborne #1 well, operated by Beacon Offshore Energy LLC, recently reinstated production in April 2024. Talos holds a 25% working interest.
Planned Downtime Updates: Following the deferral of planned drydock maintenance into the second quarter 2024, Talos mobilized the HP-1 vessel to shore for regulatory required maintenance in April. The vessel is expected to resume production in June. Talos expects the drydock to result in 5.0 – 6.0 MBoe/d of deferred production in the second quarter 2024. Talos's operational and financial guidance includes downtime estimates for the HP-1 drydock.
FIRST QUARTER 2024 RESULTS
Key Financial Highlights:
($ thousands, except per share and per Boe amounts) | Three Months Ended | ||
Total revenues | $ | 429,932 | |
Net Income (Loss) | $ | (112,439) | |
Net Income (Loss) per diluted share | $ | (0.71) | |
Adjusted Net Income (Loss) excluding CCS* | $ | (20,942) | |
Adjusted Net Income (Loss) excluding CCS per diluted share* | $ | (0.13) | |
Adjusted EBITDA excluding CCS* | $ | 267,548 | |
Adjusted EBITDA excluding CCS and hedges* | $ | 271,042 | |
Upstream Capital Expenditures | $ | 112,435 | |
Production
Production for the first quarter 2024 was 79.6 MBoe/d and was 71% oil and 80% liquids.
Three Months Ended | |||
Oil (MBbl/d) | 56.8 | ||
Natural Gas (MMcf/d) | 95.2 | ||
NGL (MBbl/d) | 6.9 | ||
Total average net daily (MBoe/d) | 79.6 | ||
Three Months Ended March 31, 2024 | ||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||
Green Canyon Area | 24.0 | 81 | % | 88 | % | 90 | % | |||||
Mississippi Canyon Area | 42.6 | 73 | % | 82 | % | 83 | % | |||||
Shelf and Gulf Coast | 13.0 | 47 | % | 58 | % | 57 | % | |||||
Total average net daily (MBoe/d) | 79.6 | 71 | % | 80 | % | 81 | % | |||||
Three Months Ended | |||
Average realized prices (excluding hedges)(1) | |||
Oil ($/Bbl) | $ | 76.01 | |
Natural Gas ($/Mcf) | $ | 2.74 | |
NGL ($/Bbl) | $ | 20.59 | |
Average realized price ($/Boe) | $ | 59.32 | |
Average NYMEX prices | |||
WTI ($/Bbl) | $ | 77.50 | |
Henry Hub ($/MMBtu) | $ | 2.15 | |
Lease Operating & General and Administrative Expenses
Total lease operating expenses for the first quarter 2024, inclusive of workover, maintenance and insurance costs, were $135.2 million, or $18.65 per Boe. Excluding workover expenses associated with the stimulation campaign, total lease operating expenses were $98.6 million, or $13.60 per Boe. Most of the 2024 projected workover expense is expected in the first half 2024.
General and Administrative expenses for the first quarter, adjusted to exclude CCS expenses, one-time transaction-related costs, and non-cash equity-based compensation, were $27.4 million, or $3.78 per Boe.
($ thousands, except per Boe amounts) | Three Months Ended | ||
Lease Operating Expenses | $ | 135,178 | |
Lease Operating Expenses per Boe | $ | 18.65 | |
Lease Operating Expenses excluding workover | $ | 98,578 | |
Lease Operating Expenses excluding workover per Boe | $ | 13.60 | |
Adjusted General & Administrative Expenses excluding CCS* | $ | 27,386 | |
Adjusted General & Administrative Expenses excluding CCS per Boe* | $ | 3.78 | |
Capital Expenditures
Upstream capital expenditures for the first quarter 2024, excluding plugging and abandonment and settled decommissioning obligations, totaled $112.4 million.
($ thousands) | Three Months Ended | ||
U.S. drilling & completions | $ | 44,081 | |
Asset management(1) | 24,982 | ||
Seismic and G&G, land, capitalized G&A and other | 43,372 | ||
Total Upstream Capital Expenditures | $ | 112,435 | |
__________________________ | |
(1) | Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. |
CCS expenses for the first quarter 2024 totaled $9.9 million, which is included in Talos's reported Adjusted EBITDA* figure. CCS capital expenditures for the first quarter 2024 totaled $17.5 million.
($ thousands) | Three Months Ended | ||
CCS Investments | |||
CCS Expenses | $ | 9,872 | |
CCS Capital Expenditures | 17,519 | ||
Total CCS Investments | $ | 27,391 | |
Plugging & Abandonment Expenses
Upstream capital expenditures for plugging and abandonment and settled decommissioning obligations for the first quarter 2024 totaled $31.4 million.
Three Months Ended | |||
Plugging & Abandonment and Decommissioning Obligations Settled(1) | $ | 31,413 | |
__________________________ | |
(1) | Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
Liquidity and Leverage
At March 31, 2024, Talos had approximately $650.2 million of liquidity, with $640.0 million undrawn on its credit facility and approximately $21.0 million in cash, less approximately $10.8 million in outstanding letters of credit. On March 31, 2024, Talos had $1,575.0 million in total debt. Net Debt* was $1,554.0 million. Net Debt to Pro Forma Last Twelve Months ("LTM") Adjusted EBITDA* was 1.0x.
OPERATIONAL & FINANCIAL GUIDANCE UPDATES
For the second quarter 2024, Talos expects average daily production of 93.0 - 96.0 MBoe/d (70% oil), which includes the impact of 5.0 – 6.0 MBOE/D from the planned HP-I drydock and a full quarter contribution from QuarterNorth.
Talos's reiterates its full year 2024 operational and financial guidance and continues to expect average daily production of 89.0 - 95.0 MBoe/d (71% oil).
Talos increased its target debt reduction amount to $550 million from the previous $400 million.
The following summarizes Talos's previously disclosed full-year 2024 operational and production guidance.
FY 2024 | |||||||
($ Millions, unless highlighted): | Low | High | |||||
Production | Oil (MMBbl) | 23.4 | 24.7 | ||||
Natural Gas (Mcf) | 40.0 | 44.2 | |||||
NGL (MMBbl) | 2.5 | 2.7 | |||||
Total Production (MMBoe) | 32.6 | 34.8 | |||||
Avg Daily Production (MBoe/d) | 89.0 | 95.0 | |||||
Cash Expenses | Cash Operating Expenses(1)(2)(4)* | $ | 510 | $ | 530 | ||
Workovers | $ | 45 | $ | 55 | |||
G&A(2)(3)* | $ | 100 | $ | 110 | |||
Capex | Upstream Capital Expenditures(5) | $ | 570 | $ | 600 | ||
P&A Expenditures | P&A, Decommissioning | $ | 90 | $ | 100 | ||
Interest | Interest Expense(6) | $ | 175 | $ | 185 | ||
(1) Includes Lease Operating Expenses and Maintenance. |
(2) Includes insurance costs. |
(3) Excludes non-cash equity-based compensation and transaction and other expenses. |
(4) Includes reimbursements under production handling agreements. |
(5) Excludes acquisitions. |
(6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. |
*Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not |
HEDGES
The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of May 7, 2024. The table includes derivative instruments assumed as part of the QuarterNorth acquisition:
Instrument Type | Avg. Daily | W.A. Swap | W.A. Sub- | W.A. Floor | W.A. Ceiling | |||||||||||
Crude – WTI | (Bbls) | (Per Bbl) | (Per Bbl) | (Per Bbl) | (Per Bbl) | |||||||||||
April - June 2024 | Fixed Swaps | 43,522 | $ | 75.13 | --- | --- | --- | |||||||||
Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | |||||||||
Long Puts | 4,000 | --- | --- | $ | 70.00 | --- | ||||||||||
Short Puts | 1,000 | --- | $ | 60.00 | --- | --- | ||||||||||
July - September 2024 | Fixed Swaps | 38,011 | $ | 75.40 | --- | --- | --- | |||||||||
Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | |||||||||
Long Puts | 4,000 | --- | --- | $ | 70.00 | --- | ||||||||||
Short Puts | 1,000 | --- | $ | 60.00 | --- | --- | ||||||||||
October - December 2024 | Fixed Swaps | 38,674 | $ | 76.07 | --- | --- | --- | |||||||||
Collar | 1,000 | --- | --- | $ | 70.00 | $ | 75.00 | |||||||||
Long Puts | 4,000 | --- | --- | $ | 70.00 | --- | ||||||||||
Short Puts | 1,000 | --- | $ | 60.00 | --- | --- | ||||||||||
January - March 2025 | Fixed Swaps | 32,000 | $ | 72.52 | --- | --- | --- | |||||||||
Collar | 3,000 | --- | --- | $ | 65.00 | $ | 84.35 | |||||||||
April - June 2025 | Fixed Swaps | 21,000 | $ | 73.12 | --- | --- | --- | |||||||||
July - September 2025 | Fixed Swaps | 14,000 | $ | 74.04 | --- | --- | --- | |||||||||
October - December 2025 | Fixed Swaps | 12,000 | $ | 74.08 | --- | --- | --- | |||||||||
Natural Gas – HH NYMEX | (MMBtu) | (Per MMBtu) | (Per MMBtu) | (Per MMBtu) | (Per MMBtu) | |||||||||||
April - June 2024 | Fixed Swaps | 38,407 | $ | 3.04 | --- | --- | --- | |||||||||
Collar | 10,000 | --- | --- | $ | 4.00 | $ | 6.90 | |||||||||
Long Puts | 13,660 | --- | --- | $ | 2.90 | --- | ||||||||||
July - September 2024 | Fixed Swaps | 30,000 | $ | 2.82 | --- | --- | --- | |||||||||
Collar | 10,000 | --- | --- | $ | 4.00 | $ | 6.90 | |||||||||
Long Puts | 13,660 | --- | --- | $ | 2.90 | --- | ||||||||||
October - December 2024 | Fixed Swaps | 35,000 | $ | 2.85 | --- | --- | --- | |||||||||
Collar | 10,000 | --- | --- | $ | 4.00 | $ | 6.90 | |||||||||
Long Puts | 13,660 | --- | --- | $ | 2.90 | --- | ||||||||||
January - March 2025 | Fixed Swaps | 60,000 | $ | 3.68 | --- | --- | --- | |||||||||
April - June 2025 | Fixed Swaps | 35,000 | $ | 3.51 | --- | --- | --- | |||||||||
July - September 2025 | Fixed Swaps | 30,000 | $ | 3.58 | --- | --- | --- | |||||||||
October - December 2025 | Fixed Swaps | 30,000 | $ | 3.58 | --- | --- | --- | |||||||||
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live over the internet, on Tuesday, May 7, 2024 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: https://www.talosenergy.com/investor-relations/events-calendar/default.aspx. Alternatively, the conference call can be accessed by dialing (800) 836-8184 (North American toll-free) or (646) 357-8785 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until May 14, 2024 and can be accessed by dialing (888) 660-6345 and using access code 98377#. For more information, please refer to the First Quarter 2024 Earnings Presentation available under Presentations and Filings on the Investor Relations section of Talos's website.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on maximizing long-term value through its Upstream Exploration & Production business in the United States Gulf of Mexico and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility, and community impact. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Clay Jeansonne
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENT
The information in this communication includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical fact included in this communication regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "will," "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast," "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on our current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: business strategy; recoverable resources and reserves; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling and property acquisitions; financial strategy, liquidity and capital required for our development program and other capital expenditures; realized oil and natural gas prices; risks related to future mergers and acquisitions and/or to realize the expected benefits of any such transaction timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling plans; availability of pipeline connections on economic terms; competition, government regulations, including new financial assurance requirements, and legislative and political developments; our ability to obtain permits and governmental approvals; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions, including the QuarterNorth acquisition, and the anticipated performance of the combined company; future leasehold or business acquisitions on desired terms; costs of developing properties; general economic conditions, including the impact of continued inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage; credit markets; volatility in the political, legal and regulatory environments ahead of the upcoming domestic and foreign presidential elections; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; our ongoing strategy with respect to our Zama asset; uncertainty regarding our future operating results and our future revenues and expenses; impact of new accounting pronouncements on earnings in future periods; and plans, objectives, expectations and intentions contained in this communication that are not historical. These forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in Israel and the Middle East, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; the effect of a possible U.S. government shutdown and resulting impact on economic conditions and delays in regulatory and permitting approvals; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2023 and Part II, Item 1A. "Risk Factors" of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, each filed with the SEC. Should any risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication.
PRODUCTION ESTIMATES
Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, adverse weather conditions such as hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.
RESERVE INFORMATION
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use the term "gross unrisked resource potential" in this release, which is not a measure of "reserves" prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These resource estimates are inherently more uncertain than estimates of reserves prepared in accordance with SEC guidelines.
USE OF NON-GAAP FINANCIAL MEASURES
This release includes the use of certain measures that have not been calculated in accordance with U.S. generally acceptable accounting principles (GAAP) such as, but not limited to, EBITDA, Adjusted EBITDA, LTM Adjusted EBITDA, Pro Forma LTM Adjusted EBITDA, Net Debt, Net Debt to LTM Adjusted EBITDA, Net Debt to Pro Forma LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage, Adjusted EBITDA excluding hedges, Adjusted EBITDA excluding CCS, Adjusted EBITDA excluding CCS and hedges, Adjusted EBITDA Free Cash Flow excluding CCS, Adjusted Net Income (Loss) excluding CCS. Non-GAAP financial measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations for non-GAAP measure to GAAP measures are included at the end of this release.
Talos Energy Inc. Consolidated Balance Sheets (In thousands, except share amounts) | ||||||
March 31, 2024 | December 31, 2023 | |||||
(Unaudited) | ||||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 21,001 | $ | 33,637 | ||
Accounts receivable: | ||||||
Trade, net | 248,892 | 178,977 | ||||
Joint interest, net | 143,801 | 79,337 | ||||
Other, net | 16,652 | 19,296 | ||||
Assets from price risk management activities | 18,753 | 36,152 | ||||
Prepaid assets | 75,776 | 64,387 | ||||
Other current assets | 16,036 | 10,389 | ||||
Total current assets | 540,911 | 422,175 | ||||
Property and equipment: | ||||||
Proved properties | 9,268,050 | 7,906,295 | ||||
Unproved properties, not subject to amortization | 654,906 | 268,315 | ||||
Other property and equipment | 34,440 | 34,027 | ||||
Total property and equipment | 9,957,396 | 8,208,637 | ||||
Accumulated depreciation, depletion and amortization | (4,383,970) | (4,168,328) | ||||
Total property and equipment, net | 5,573,426 | 4,040,309 | ||||
Other long-term assets: | ||||||
Restricted cash | 103,360 | 102,362 | ||||
Assets from price risk management activities | 5,355 | 17,551 | ||||
Equity method investments | 108,036 | 146,049 | ||||
Other well equipment | 63,507 | 54,277 | ||||
Notes receivable, net | 16,619 | 16,207 | ||||
Operating lease assets | 12,676 | 11,418 | ||||
Other assets | 10,494 | 5,961 | ||||
Total assets | $ | 6,434,384 | $ | 4,816,309 | ||
LIABILITIES AND STOCKHOLDERSʼ EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 136,833 | $ | 84,193 | ||
Accrued liabilities | 272,231 | 227,690 | ||||
Accrued royalties | 71,007 | 55,051 | ||||
Current portion of long-term debt | — | 33,060 | ||||
Current portion of asset retirement obligations | 71,799 | 77,581 | ||||
Liabilities from price risk management activities | 74,033 | 7,305 | ||||
Accrued interest payable | 21,106 | 42,300 | ||||
Current portion of operating lease liabilities | 3,543 | 2,666 | ||||
Other current liabilities | 46,310 | 48,769 | ||||
Total current liabilities | 696,862 | 578,615 | ||||
Long-term liabilities: | ||||||
Long-term debt | 1,533,952 | 992,614 | ||||
Asset retirement obligations | 1,037,533 | 819,645 | ||||
Liabilities from price risk management activities | 3,747 | 795 | ||||
Operating lease liabilities | 18,271 | 18,211 | ||||
Other long-term liabilities | 391,834 | 251,278 | ||||
Total liabilities | 3,682,199 | 2,661,158 | ||||
Commitments and contingencies | ||||||
Stockholdersʼ equity: | ||||||
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding | — | — | ||||
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,307,298 and 127,480,361 | 1,873 | 1,275 | ||||
Additional paid-in capital | 3,257,972 | 2,549,097 | ||||
Accumulated deficit | (460,156) | (347,717) | ||||
Treasury stock, at cost; 3,400,000 and 3,400,000 shares as of March 31, 2024 and December 31, | (47,504) | (47,504) | ||||
Total stockholdersʼ equity | 2,752,185 | 2,155,151 | ||||
Total liabilities and stockholdersʼ equity | $ | 6,434,384 | $ | 4,816,309 | ||
Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per share amounts) (Unaudited) | ||||||
Three Months Ended March 31, | ||||||
2024 | 2023 | |||||
Revenues: | ||||||
Oil | $ | 393,221 | $ | 292,694 | ||
Natural gas | 23,698 | 20,183 | ||||
NGL | 13,013 | 9,705 | ||||
Total revenues | 429,932 | 322,582 | ||||
Operating expenses: | ||||||
Lease operating expense | 135,178 | 81,362 | ||||
Production taxes | 544 | 606 | ||||
Depreciation, depletion and amortization | 215,664 | 147,323 | ||||
Accretion expense | 26,903 | 19,414 | ||||
General and administrative expense | 69,841 | 63,187 | ||||
Other operating (income) expense | (86,043) | 2,838 | ||||
Total operating expenses | 362,087 | 314,730 | ||||
Operating income (expense) | 67,845 | 7,852 | ||||
Interest expense | (50,845) | (37,581) | ||||
Price risk management activities income (expense) | (87,062) | 58,937 | ||||
Equity method investment income (expense) | (8,054) | 7,443 | ||||
Other income (expense) | (55,896) | 6,666 | ||||
Net income (loss) before income taxes | (134,012) | 43,317 | ||||
Income tax benefit (expense) | 21,573 | 46,543 | ||||
Net income (loss) | $ | (112,439) | $ | 89,860 | ||
Net income (loss) per common share: | ||||||
Basic | $ | (0.71) | $ | 0.85 | ||
Diluted | $ | (0.71) | $ | 0.84 | ||
Weighted average common shares outstanding: | ||||||
Basic | 158,490 | 105,634 | ||||
Diluted | 158,490 | 106,950 | ||||
Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) (Unaudited) | ||||||
Three Months Ended March 31, | ||||||
2024 | 2023 | |||||
Cash flows from operating activities: | ||||||
Net income (loss) | $ | (112,439) | $ | 89,860 | ||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||
Depreciation, depletion, amortization and accretion expense | 242,567 | 166,737 | ||||
Amortization of deferred financing costs and original issue discount | 2,598 | 4,148 | ||||
Equity-based compensation expense | 2,754 | 3,938 | ||||
Price risk management activities (income) expense | 87,062 | (58,937) | ||||
Net cash received (paid) on settled derivative instruments | (3,494) | (12,323) | ||||
Equity method investment (income) expense | 8,054 | (7,443) | ||||
Loss (gain) on extinguishment of debt | 60,256 | — | ||||
Settlement of asset retirement obligations | (27,907) | (10,113) | ||||
Loss (gain) on sale of business | (86,940) | — | ||||
Changes in operating assets and liabilities: | ||||||
Accounts receivable | 8,020 | 36,821 | ||||
Other current assets | (5,818) | 7,735 | ||||
Accounts payable | 10,707 | (4,894) | ||||
Other current liabilities | (65,249) | (116,637) | ||||
Other non-current assets and liabilities, net | (23,745) | (36,035) | ||||
Net cash provided by (used in) operating activities | 96,426 | 62,857 | ||||
Cash flows from investing activities: | ||||||
Exploration, development and other capital expenditures | (146,077) | (103,962) | ||||
Proceeds from (cash paid for) acquisitions, net of cash acquired | (916,045) | 17,617 | ||||
Contributions to equity method investees | (17,519) | (12,835) | ||||
Investment in intangible assets | — | (7,796) | ||||
Proceeds from sales of businesses | 141,997 | — | ||||
Net cash provided by (used in) investing activities | (937,644) | (106,976) | ||||
Cash flows from financing activities: | ||||||
Issuance of common stock | 387,717 | — | ||||
Issuance of senior notes | 1,250,000 | — | ||||
Redemption of senior notes | (897,116) | — | ||||
Proceeds from Bank Credit Facility | 670,000 | 275,000 | ||||
Repayment of Bank Credit Facility | (545,000) | (110,000) | ||||
Deferred financing costs | (25,505) | (11,346) | ||||
Other deferred payments | (672) | — | ||||
Payments of finance lease | (4,324) | (3,987) | ||||
Purchase of treasury stock | — | (25,173) | ||||
Employee stock awards tax withholdings | (5,520) | (7,378) | ||||
Net cash provided by (used in) financing activities | 829,580 | 117,116 | ||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (11,638) | 72,997 | ||||
Cash, cash equivalents and restricted cash: | ||||||
Balance, beginning of period | 135,999 | 44,145 | ||||
Balance, end of period | $ | 124,361 | $ | 117,142 | ||
Supplemental non-cash transactions: | ||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 101,794 | $ | 174,597 | ||
Supplemental cash flow information: | ||||||
Interest paid, net of amounts capitalized | $ | 55,224 | $ | 40,988 | ||
SUPPLEMENTAL NON-GAAP INFORMATION
Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies. In addition, we believe that non-GAAP measures excluding CCS are a meaningful measure of financial performance that can be used by investors, analysts and management in evaluating the performance of our "go-forward" business after giving effect to our CCS divestiture during the first quarter of 2024, and will assist such readers of our financial statements in considering the results of this business in comparative periods.
Reconciliation of General and Administrative Expenses to Adjusted General and Administrative Expenses Excluding CCS
We believe the presentation of Adjusted General and Administrative Expenses excluding CCS provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted General & Administrative Expenses excluding CCS has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
General and Administrative Expenses. General and Administrative Expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment.
($ thousands) | Three Months Ended | ||
Reconciliation of General & Administrative Expenses to Adjusted General & Administrative Expenses excluding CCS: | |||
Total General and administrative expense | $ | 69,841 | |
CCS Segment | (1,965) | ||
Transaction and other (income) expenses(1) | (37,783) | ||
Non-cash equity-based compensation expense | (2,707) | ||
Adjusted General & Administrative Expenses excluding CCS | $ | 27,386 | |
__________________________ | |
(1) | Transaction expenses includes $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. |
Reconciliation of Net Income (Loss) to EBITDA, Adjusted EBITDA and Adjusted EBITDA Excluding CCS
"EBITDA," "Adjusted EBITDA" and "Adjusted EBITDA excluding CCS" provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA, Adjusted EBITDA, and Adjusted EBITDA excluding CCS have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
EBITDA. Net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion and amortization; and accretion expense.
Adjusted EBITDA. EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.
Adjusted EBITDA excluding hedges. We have historically provided as a supplement to—rather than in lieu of—Adjusted EBITDA including hedges, provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time.
Adjusted EBITDA excluding CCS. Adjusted EBITDA plus equity method investment loss, general and administrative expense, other operating expenses (income), other income, and non-cash equity-based compensation expense attributable to CCS.
The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges for each of the periods indicated (in thousands):
Three Months Ended | ||||||||||||
($ thousands) | March 31, | December 31, | September 30, | June 30, | ||||||||
Reconciliation of Net Income (Loss) to Adjusted EBITDA: | ||||||||||||
Net Income (loss) | $ | (112,439) | $ | 85,898 | $ | (2,103) | $ | 13,677 | ||||
Interest expense | 50,845 | 44,295 | 45,637 | 45,632 | ||||||||
Income tax expense (benefit) | (21,573) | (5,081) | (15,865) | 6,892 | ||||||||
Depreciation, depletion and amortization | 215,664 | 183,058 | 163,359 | 169,794 | ||||||||
Accretion expense | 26,903 | 22,722 | 21,256 | 22,760 | ||||||||
EBITDA | 159,400 | 330,892 | 212,284 | 258,755 | ||||||||
Transaction and other (income) expenses(1) | (49,157) | 5,504 | (64,321) | 3,513 | ||||||||
Decommissioning obligations(2) | 855 | 2,425 | 7,972 | 741 | ||||||||
Derivative fair value (gain) loss(3) | 87,062 | (94,596) | 98,802 | (26,197) | ||||||||
Net cash received (paid) on settled derivative instruments(3) | (3,494) | 1,017 | (6,313) | 8,162 | ||||||||
Loss on extinguishment of debt | 60,256 | — | — | — | ||||||||
Non-cash equity-based compensation expense | 2,754 | 3,873 | 393 | 4,749 | ||||||||
Adjusted EBITDA | 257,676 | 249,115 | 248,817 | 249,723 | ||||||||
Add: Net cash (received) paid on settled derivative instruments(3) | 3,494 | (1,017) | 6,313 | (8,162) | ||||||||
Adjusted EBITDA excluding hedges | $ | 261,170 | $ | 248,098 | $ | 255,130 | $ | 241,561 | ||||
__________________________ | |
(1) | Transaction expenses includes $28.1 million in costs related to the QuarterNorth acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024, $0.9 million in costs related to the EnVen Energy Corporation ("EnVen") Acquisition, inclusive of $0.5 million in severance expense for the three months ended December 31, 2023, $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense for the three months ended September 30, 2023 and $2.7 million in costs related to the EnVen acquisition, inclusive of $1.4 million in severance expense for the three months ended June 30, 2023. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS. For the three months ended September 30, 2023, the amount includes a $66.2 million gain on the divestiture of 49.9% equity interest in our subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso. |
(2) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in "Other operating (income) expense" on our consolidated statements of operations. |
(3) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
($ thousands, except per Boe amounts) | Three Months Ended | ||
Reconciliation of Adjusted EBITDA to Adjusted EBITDA excluding CCS: | |||
Adjusted EBITDA | $ | 257,676 | |
CCS Costs: | |||
Equity method investment loss | 7,970 | ||
General and administrative expense | 1,965 | ||
Other operating expense | (11) | ||
Other income | (5) | ||
Non-cash equity-based compensation expense | (47) | ||
Adjusted EBITDA excluding CCS | 267,548 | ||
Add: Net cash paid on settled derivative instruments(1) | 3,494 | ||
Adjusted EBITDA excluding CCS and hedges | $ | 271,042 | |
Production: | |||
Boe(2) | 7,248 | ||
Adjusted EBITDA excluding CCS margin and Adjusted EBITDA excluding CCS and hedges margin: | |||
Adjusted EBITDA excluding CCS per Boe(2) | $ | 36.91 | |
Adjusted EBITDA excluding CCS and hedges per Boe(1)(2) | $ | 37.40 | |
__________________________ | |
(1) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
(2) | One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow Excluding CCS and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow Excluding CCS
"Adjusted Free Cash Flow excluding CCS" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Free Cash Flow excluding CCS has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.
Interest Expense. Actual interest expense per the income statement.
Talos did not pay any cash income taxes in the period, therefore cash income taxes have no impact to the reported Adjusted Free Cash Flow before changes in working capital number.
($ thousands) | Three Months Ended | ||
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow excluding CCS (before changes | |||
Adjusted EBITDA | $ | 257,676 | |
Upstream capital expenditures | (112,435) | ||
Plugging & abandonment | (27,907) | ||
Decommissioning obligations settled | (3,506) | ||
CCS capital expenditures | (17,519) | ||
Interest expense(1) | (45,970) | ||
Adjusted Free Cash Flow (before changes in working capital) | 50,339 | ||
CCS capital expenditures | 17,519 | ||
CCS Costs: | |||
Equity method investment loss | 7,970 | ||
General and administrative expense | 1,965 | ||
Other operating expense | (11) | ||
Other income | (5) | ||
Non-cash equity-based compensation expense | (47) | ||
Adjusted Free Cash Flow excluding CCS (before changes in working capital) | $ | 77,730 | |
__________________________ | |
(1) | Interest expense excludes $4.9 million in fees associated with the unutilized bridge loan that we do not view as a meaningful indicator of our operating performance. |
($ thousands) | Three Months Ended | ||
Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow excluding | |||
Net cash provided by operating activities(1) | $ | 96,426 | |
(Increase) decrease in operating assets and liabilities | 76,085 | ||
Upstream capital expenditures(2) | (112,435) | ||
Decommissioning obligations settled | (3,506) | ||
CCS capital expenditures | (17,519) | ||
Transaction and other (income) expenses(3) | 37,783 | ||
Decommissioning obligations(4) | 855 | ||
Amortization of deferred financing costs and original issue discount | (2,598) | ||
Income tax benefit | (21,573) | ||
Other adjustments | (3,179) | ||
Adjusted Free Cash Flow (before changes in working capital) | 50,339 | ||
CCS capital expenditures | 17,519 | ||
CCS Costs: | |||
Equity method investment loss | 7,970 | ||
General and administrative expense | 1,965 | ||
Other operating expense | (11) | ||
Other income | (5) | ||
Non-cash equity-based compensation expense | (47) | ||
Adjusted Free Cash Flow excluding CCS (before changes in working capital) | $ | 77,730 | |
__________________________ | |
(1) | Includes settlement of asset retirement obligations. |
(2) | Includes accruals and excludes acquisitions. |
(3) | Transaction expenses includes $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS. |
(4) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share and to Adjusted Net Income (Loss) excluding CCS and Adjusted Earnings per Share excluding CCS
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.
Three Months Ended March 31, 2024 | |||||||||
($ thousands, except per share amounts) | Basic per Share | Diluted per Share | |||||||
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) excluding CCS: | |||||||||
Net Income (loss) | $ | (112,439) | $ | (0.71) | $ | (0.71) | |||
Transaction and other (income) expenses(1) | (49,157) | $ | (0.31) | $ | (0.31) | ||||
Decommissioning obligations(2) | 855 | $ | 0.01 | $ | 0.01 | ||||
Derivative fair value loss(3) | 87,062 | $ | 0.55 | $ | 0.55 | ||||
Net cash received on paid derivative instruments(3) | (3,494) | $ | (0.02) | $ | (0.02) | ||||
Unutilized bridge loan fees | 4,875 | $ | 0.03 | $ | 0.03 | ||||
Non-cash income tax benefit | (21,573) | $ | (0.14) | $ | (0.14) | ||||
Loss on extinguishment of debt | 60,256 | $ | 0.38 | $ | 0.38 | ||||
Non-cash equity-based compensation expense | 2,754 | $ | 0.02 | $ | 0.02 | ||||
Adjusted Net Income (Loss)(4) | $ | (30,861) | $ | (0.19) | $ | (0.19) | |||
CCS Costs: | |||||||||
Equity method investment loss | 7,970 | $ | 0.05 | $ | 0.05 | ||||
General and administrative expense | 1,965 | $ | 0.01 | $ | 0.01 | ||||
Other operating expense | (11) | $ | (0.00) | $ | (0.00) | ||||
Other income | (5) | $ | (0.00) | $ | (0.00) | ||||
Adjusted Net Income (Loss) excluding CCS(4) | $ | (20,942) | $ | (0.13) | $ | (0.13) | |||
Weighted average common shares outstanding at March 31, 2024: | |||||||||
Basic | 158,490 | ||||||||
Diluted | 158,490 | ||||||||
__________________________ | |
(1) | Transaction expenses includes $28.1 million in costs related to the QuarterNorth acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS. |
(2) | Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
(3) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. |
(4) | The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Pro Forma LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies.
Net Debt. Total Debt principal minus cash and cash equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
($ thousands) | March 31, 2024 | ||
Reconciliation of Net Debt: | |||
9.000% Second-Priority Senior Secured Notes – due February 2029 | $ | 625,000 | |
9.375% Second-Priority Senior Secured Notes – due February 2031 | 625,000 | ||
Bank Credit Facility – matures March 2027 | 325,000 | ||
Total Debt | 1,575,000 | ||
Less: Cash and cash equivalents | (21,001) | ||
Net Debt | $ | 1,553,999 | |
Calculation of LTM Adjusted EBITDA: | |||
Adjusted EBITDA for three months period ended June 30, 2023 | $ | 249,723 | |
Adjusted EBITDA for three months period ended September 30, 2023 | 248,817 | ||
Adjusted EBITDA for three months period ended December 31, 2023 | 249,115 | ||
Adjusted EBITDA for three months period ended March 31, 2024 | 257,676 | ||
LTM Adjusted EBITDA | $ | 1,005,331 | |
Acquired Assets Adjusted EBITDA: | |||
Adjusted EBITDA for three months period ended June 30, 2023 | $ | 95,707 | |
Adjusted EBITDA for three months period ended September 30, 2023 | 161,427 | ||
Adjusted EBITDA for three months period ended December 31, 2023 | 129,063 | ||
Adjusted EBITDA for period January 1, 2024 to March 4, 2024 | 99,490 | ||
LTM Adjusted EBITDA from Acquired Assets | $ | 485,687 | |
Pro Forma LTM Adjusted EBITDA | $ | 1,491,018 | |
Reconciliation of Net Debt to Pro Forma LTM Adjusted EBITDA: | |||
Net Debt / Pro Forma LTM Adjusted EBITDA(1) | 1.0x | ||
__________________________ | |
(1) | Net Debt / Pro Forma LTM Adjusted EBITDA figure excludes the Finance Lease. Had the Finance Lease been included, Net Debt / Pro Forma LTM Adjusted EBITDA would have been 1.1x. |
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SOURCE Talos Energy
