# Talos Energy Inc.: Form 10-Q for the period ended Sep 30, 2024

- Company: [Talos Energy Inc.](/companies/talo.md) (CIK 1724965)
- Form: 10-Q
- Filed: 2024-11-12
- Accepted by EDGAR: Nov 12, 2024, 16:44 ET
- Period: 2024-09-30
- Accession: 0000950170-24-125580
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1724965/000095017024125580/talo-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1724965/000095017024125580/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-07-01 to 2024-09-30 | $509.3m | us-gaap:Revenues |
| Revenue | 9 months, 2024-01-01 to 2024-09-30 | $1.49bn | us-gaap:Revenues |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | $23.5m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | $145.8m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-07-01 to 2024-09-30 | $46.3m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2024-01-01 to 2024-09-30 | $146.1m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | $18.1m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | −$4.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | $88.2m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | −$11.9m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.49 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | −$0.07 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.49 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | −$0.07 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 180,561,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 174,108,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $613.3m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 9 months, 2024-01-01 to 2024-09-30 | $45.2m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-09-30 | $45.5m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $655.6m | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $6.40bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $677.9m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-09-30 | $3.58bn | us-gaap:Liabilities |
| Long-term debt | at 2024-09-30 | $1.34bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2024-09-30 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2024-09-30 | $2.82bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 65,607 characters.

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2023 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2023 Annual Report.

### Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world.

We have historically focused our oil and gas exploration and production operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”), of which the Company’s only reportable segment was the Upstream Segment. On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). Subsequent to the TLCS Divestiture and our sale of the entire CCS business, we had one operating segment. See Part I, Item 1. “Financial Statements — Note 14 — *Segment Information”* for additional information on our business segments and Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for additional information on the TLCS Divestiture.

### Significant Developments

The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2024, with the SEC on August 8, 2024.

***Limited Duration Stockholder Rights Agreement —*** On October 1, 2024, our Board of Directors (the “Board”) adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one preferred share purchase right on each outstanding share of the Company’s common stock, par value $0.01 per share (the “Common Stock”), which became payable on October 11, 2024. The Board adopted the Rights Agreement to deter any future efforts by one person or a group to acquire actual, de facto or negative control of the Company through open market accumulation, or other tactics potentially disadvantaging the interests of all stockholders, without paying all stockholders an appropriate control premium or providing the Company's Board sufficient time to make informed decisions in the best interest of all stockholders. In general terms, the Rights Agreement imposes significant dilution upon any person or group that acquires 25% or more of the outstanding Common Stock, including through certain derivatives agreements, without the approval of the Board (an “Acquiring Person”). The Rights Agreement is not intended to deter offers that are fair and otherwise in the best interests of the Company's stockholders, and does not prevent the Board from considering any proposal. In adopting the Rights Agreement, the Board noted, in particular, the continued accumulation of approximately 24% of shares of Talos common stock by Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial”). The Rights Agreement is similar to those adopted by other publicly traded companies and is intended to enable all Talos stockholders to realize the long-term value of their investment and protect Talos from any future efforts to obtain control of the Company that are inconsistent with the best interests of its stockholders. See Part I, Item 1. “Financial Statements — Note 15 — *Subsequent Events”* for more information on the Rights Agreement and Item 1. “Financial Statements — Note 12 — *Related Party Transactions”* for additional information on Control Empresarial.

The Rights Agreement is filed as Exhibit 4.11 to this Quarterly Report. This description of the Rights Agreement in this Quarterly Report does not purport to be complete and is qualified in its entirety by reference to Exhibit 4.11.

***Chief Executive Officer Transition —*** On August 29, 2024, Timothy S. Duncan departed his role as President and Chief Executive Officer of the Company, effective immediately. The Company also announced that Joseph A. Mills will serve as Interim Chief Executive Officer and President, effective as of August 29, 2024. The Board is working to identify a permanent Chief Executive Officer and has retained an executive search firm to assist in the process.

### Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

***QuarterNorth Acquisition —*** On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of Mexico (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

***EnVen Acquisition —*** On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

***Third Party Planned Downtime —*** Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. For example, we produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

During the second quarter of 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the nine months ended September 30, 2024 based on production rates prior to the shut-in.

### Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2023 Annual Report.

***Volatility in Oil, Natural Gas and NGL Prices —*** Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.

During the period January 1, 2024 through September 30, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.25 per MMBtu. The price the Company realizes on natural gas sales is based on the MMBtu content of such natural gas. We convert MMBtu sales volumes to Mcf volumes for reporting purposes using MMBtu per Mcf factors per third party natural gas processing plant statements. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments”* for additional information regarding our commodity derivative positions as of September 30, 2024.

The U.S. Energy Information Administration (“EIA”) published its October 2024 Short-Term Energy Outlook on October 8, 2024. Oil prices fell in September as concerns over global oil demand growth outweighed declines in oil inventories and a decision made by OPEC Plus to delay production increases until December 2024. However, oil prices rose in early October after recent military actions involving Israel, Lebanon, and Iran. The potential for further escalation creates significant uncertainty, increasing the possibility for supply disruptions and price volatility. The EIA expects the NYMEX WTI spot prices to average $71.97 per barrel in the fourth quarter of 2024 and $73.13 per barrel in 2025. The EIA expects the Henry Hub price to continue rising to around $2.80 per MMBtu in the fourth quarter of 2024 and to further increase to around $3.10 per MMBtu on average in 2025 as liquefied natural gas exports, a component of total natural gas demand, increase with the addition of capacity.

***Inflation of Cost of Goods, Services and Personnel —*** Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. Sustained levels of high inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Inflation may also result in higher interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.

The U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. Sustained levels of high inflation generally cause the U.S. Federal Reserve (the “Fed”) and other central banks to increase interest rates. The Fed raised its benchmark interest rate 11 times between March 2022 and July 2023 to curb inflation. The Fed wants inflation to return to its 2% goal over time and it is still high in absolute terms. The Fed has lowered its benchmark interest rate twice since September 2024 by an aggregate 75 basis points to a new range of 4.50%-4.75% from its 23-year high of 5.25% to 5.50%. Future changes to the benchmark interest rate remain uncertain.

***Impairment of Oil and Natural Gas Properties —*** Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and nine months ended September 30, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At September 30, 2024 our ceiling test computation was based on SEC pricing of $80.66 per Bbl of oil, $2.32 per Mcf of natural gas and $19.06 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning October 1, 2023 and ending September 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $72.77 per Bbl of oil, $2.10 per Mcf of natural gas and $17.15 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $293.0 million.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2023 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in SEC pricing or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

***BOEM Bonding Rule —*** On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the U.S. federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period for full payment of a supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM anticipates it will take up to 24 months to complete the processing of financial assurance demands for execution. The final rule was challenged in the U.S. District Court for the Western District of Louisiana by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. Although implementation of the rule is not currently stayed, the outcome of these challenges remain uncertain.

As discussed in our 2023 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry,” we may be unable to provide the financial assurances in the amounts and under the time periods required by the new rule. If we are unable to comply with these requirements, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including assessing civil penalties, commencing proceedings to suspend our production and other operations or canceling our affected federal offshore leases. In addition, as a result of continuing adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of bonding companies have left the offshore surety market over the last twelve months, which has materially reduced the availability of surety bonds for projects in the OCS. As a result, there may not be sufficient surety bonds capacity available for companies in the OCS to comply with the new financial assurances rule. Our inability to obtain adequate supplemental financial assurance in order to comply with BOEM’s final rule, including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our financial condition, cash flows, business, properties, liquidity and results of operations.

***Deepwater Operations —*** We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

***Oil Spill Response Plan —*** We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE biennially, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

***Hurricanes, Tropical Storms and Loop Currents —*** Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future production and revenues and increased lease operating expenses for evacuations and repairs.

***Five-Year Offshore Oil and Gas Leasing Program Update —*** Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, BOEM prepares and maintains forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the OCS. As previously disclosed in our 2023 Annual Report, we were the high bidder on thirteen offshore Gulf of Mexico blocks related to Lease Sale 261 held by BOEM and awarded four leases. Subsequently, we were awarded leases on our remaining high-bid blocks. Additionally, QuarterNorth was the high bidder on four offshore blocks related to Lease Sale 261 and they were also awarded leases on all of their high-bid blocks.

The 2024-2029 national program began on July 1, 2024, and will continue through June 30, 2029. It is possible, however, that this program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and Earthjustice representing multiple environmental groups, both of which are challenging BOEM’s actions. Despite these challenges, on April 1, 2024, BOEM announced the availability of the Area Identification for proposed Gulf of Mexico lease sales 262, 263 and 264 pursuant to the 2024-2029 national program. Lease Sale 262 is tentatively scheduled for 2025.

***Endangered Species —*** On August 19, 2024, a U.S. District Court in Maryland ruled in favor of a coalition of environmental groups that, in 2020, filed suit against the National Marine Fisheries Service (“NMFS”), claiming that NMFS’s 2020 Biological Opinion, along with its associated reasonable and prudent alternative and incidental take statement, covering all activities associated with the OCS oil and gas program in the Gulf of Mexico, did not comply with the Endangered Species Act (“ESA”) or the Administrative Procedure Act. In her ruling, the Maryland District Court Judge vacated the 2020 Biological Opinion effective December 20, 2024. On September 16, 2024, NMFS filed a motion to alter or amend the Maryland District Court’s August 19, 2024 judgment and order requiring vacatur of the 2020 Biological Opinion by December 20, 2024, stating that it is unable to issue a new Biological Opinion by that date. On October 21, 2024, the Maryland District Court extended the vacatur deadline until May 21, 2025, which NMFS believes provides sufficient time to prepare and issue a new Biological Opinion. Further, industry groups appealed the Maryland District Court’s decision to the U.S. Court of Appeals for the Fourth Circuit. The outcome of that challenge remains uncertain. Although NMFS intends to prepare a new Biological Opinion in advance of the May 2025 deadline, any revised Biological Opinion that NMFS issues may face similar scrutiny as the 2020 Biological Opinion and may also be subject to legal challenge. Without an active OCS Gulf of Mexico oil and gas program Biological Opinion in place, all permits, plans and government actions would likely require individual project-specific ESA consultations between BOEM or BSEE (as applicable) and NMFS, which due to significant delay could adversely impact our ability to obtain plans, permits and government approvals required for our Gulf of Mexico operations until a new Biological Opinion is issued by NMFS. See Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species” of our 2023 Annual Report for additional information regarding the potential risks of these regulatory developments to our operations.

### How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

- production volumes;
- realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
- lease operating expenses;
- capital expenditures; and
- Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

### Results of Operations

### Revenue

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

| Revenues: | Three Months Ended September 30, 2024 | 2023 | Change | Nine Months Ended September 30, 2024 | 2023 | Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $467,605 | $359,404 | $108,201 | $1,368,234 | $995,081 | $373,153 |
| Natural gas | 25,930 | 16,871 | 9,059 | 75,688 | 53,383 | 22,305 |
| NGL | 15,751 | 6,860 | 8,891 | 44,461 | 24,463 | 19,998 |
| Total revenues | $509,286 | $383,135 | $126,151 | $1,488,383 | $1,072,927 | $415,456 |
| **Production Volumes:** |  |  |  |  |  |  |
| Oil (MBbls) | 6,258 | 4,451 | 1,807 | 17,734 | 13,358 | 4,376 |
| Natural gas (MMcf) | 10,853 | 6,005 | 4,848 | 29,593 | 19,769 | 9,824 |
| NGL (MBbls) | 811 | 403 | 408 | 2,146 | 1,318 | 828 |
| Total production volume (MBoe) | 8,878 | 5,855 | 3,023 | 24,812 | 17,971 | 6,841 |
| **Daily Production Volumes by Product:** |  |  |  |  |  |  |
| Oil (MBblpd) | 68.0 | 48.4 | 19.6 | 64.7 | 48.9 | 15.8 |
| Natural gas (MMcfpd) | 118.0 | 65.3 | 52.7 | 108.0 | 72.4 | 35.6 |
| NGL (MBblpd) | 8.8 | 4.4 | 4.4 | 7.8 | 4.8 | 3.0 |
| Total production volume (MBoepd) | 96.5 | 63.7 | 32.8 | 90.5 | 65.8 | 24.7 |
| **Average Sale Price Per Unit:** |  |  |  |  |  |  |
| Oil (per Bbl) | $74.72 | $80.75 | $(6.03) | $77.15 | $74.49 | $2.66 |
| Natural gas (per Mcf) | $2.39 | $2.81 | $(0.42) | $2.56 | $2.70 | $(0.14) |
| NGL (per Bbl) | $19.42 | $17.02 | $2.40 | $20.72 | $18.56 | $2.16 |
| Price per Boe | $57.36 | $65.44 | $(8.08) | $59.99 | $59.70 | $0.29 |
| Price per Boe (including realized commodity derivatives) | $58.05 | $64.36 | $(6.31) | $59.38 | $59.12 | $0.26 |

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

| Revenues: | Three Months Ended September 30, 2024 vs 2023 Price | Volume | Total | Nine Months Ended September 30, 2024 vs 2023 Price | Volume | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $(37,714) | $145,915 | $108,201 | $47,185 | $325,968 | $373,153 |
| Natural gas | (4,564) | 13,623 | 9,059 | (4,220) | 26,525 | 22,305 |
| NGL | 1,947 | 6,944 | 8,891 | 4,630 | 15,368 | 19,998 |
| Total revenues | $(40,331) | $166,482 | $126,151 | $47,595 | $367,861 | $415,456 |

34

***Three Months Ended September 30, 2024 and 2023 Volumetric Analysis —*** Production volumes increased by 32.8 MBoepd to 96.5 MBoepd. The increase was primarily due to 26.2 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there was 9.5 MBoepd production from our operated Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023 as well as 2.9 MBoepd production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by a decrease of 4.2 MBoepd of production due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, there was a decrease of approximately 2.7 MBoepd due to well performance and natural production declines.

***Nine Months Ended September 30, 2024 and 2023 Volumetric Analysis —*** Production volumes increased by 24.7 MBoepd to 90.5 MBoepd. The increase was primarily due to 20.6 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.1 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, production volumes increased 10.0 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by decreases of 5.0 MBoepd due to well performance and natural production declines as well as 1.4 MBoepd due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, we deferred approximately 1.6 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

### Operating Expenses

### Lease Operating Expense

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

|  | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Lease operating expenses | $163,347 | $103,548 | $455,835 | $286,075 |
| Lease operating expenses per Boe | $18.40 | $17.69 | $18.37 | $15.92 |

***Three Months Ended September 30, 2024 and 2023 —*** Lease operating expense for the three months ended September 30, 2024 increased by approximately $59.8 million, or 58%. This increase was primarily related to lease operating expenses of $63.8 million incurred in connection with assets acquired in the QuarterNorth Acquisition. Included in the increase during the three months ended September 30, 2024 is $33.1 million in facility and well workover expenses at the Gunflint Field.

***Nine Months Ended September 30, 2024 and 2023 —*** Lease operating expense for the nine months ended September 30, 2024 increased by approximately $169.8 million, or 59%. This increase was related to lease operating expenses of $116.7 million incurred in connection with assets acquired in the QuarterNorth Acquisition as well as a $10.1 million increase in lease operating expenses due to the EnVen Acquisition that closed in mid-first quarter 2023.

The increase in lease operating expense related to the QuarterNorth Acquisition included a $33.4 million increase in facility and well workover expenses at the Gunflint Field.

Additionally, there was a $54.2 million increase in facility and workover expense primarily related to the HP-I and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field associated with our historical operations. The increase attributable to our historical operations was partially offset by $14.7 million in lower marine and helicopter transportation costs, commodity transportation costs and contract labor.

### Depreciation, Depletion and Amortization

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

|  | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Depreciation, depletion and amortization | $274,249 | $163,359 | $749,004 | $480,476 |

***Three Months Ended September 30, 2024 and 2023 —*** Depreciation, depletion and amortization expense for the three months ended September 30, 2024 increased by approximately $110.9 million, or 68% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $3.11 per Boe, or 11%, on our proved oil and natural gas properties.

***Nine Months Ended September 30, 2024 and 2023 —*** Depreciation, depletion and amortization expense for the nine months ended September 30, 2024 increased by approximately $268.5 million, or 56%. This was due to an increase of $3.54 per Boe, or 13%, in the depletion rate on our proved oil and natural gas properties due to our amortization base increasing disproportionately to the increase in our reserve base. Our amortization base increased primarily due to the proved properties acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

### General and Administrative Expense

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

|  | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Upstream Segment | $39,694 | $21,054 | $141,949 | $108,310 |
| CCS Segment | — | 2,472 | 1,965 | 8,246 |
| Unallocated corporate | 2,172 | 1,362 | 16,040 | 4,701 |
| Total general and administrative expense | $41,866 | $24,888 | $159,954 | $121,257 |
| Upstream general and administrative expense per Boe | $4.47 | $3.60 | $5.72 | $6.03 |

***Three Months Ended September 30, 2024 and 2023 —*** General and administrative expense for the three months ended September 30, 2024 increased by approximately $17.0 million, or 68%. This increase was primarily due to an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. Additionally, there was an increase related to Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $3.1 million or $0.35 per Boe as well as an increase in non-cash equity-based compensation of $2.9 million. These increases were partially offset by a decrease in the CCS Segment expenses of $2.5 million due to the TLCS Divestiture. Additionally, Upstream Segment transaction costs for the EnVen Acquisition decreased $1.5 million or $0.26 per Boe. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for further discussion.

***Nine Months Ended September 30, 2024 and 2023 —*** General and administrative expense for the nine months ended September 30, 2024 increased by approximately $38.7 million, or 32%. This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $45.2 million or $2.84 per Boe. Unallocated corporate reflects an increase in transaction costs and severance costs of $8.4 million related to the TLCS Divestiture. Additionally, there was an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $39.7 million or $2.21 per Boe. Additionally, the CCS Segment expenses decreased by $6.3 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for further discussion.

### Miscellaneous

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

|  | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Accretion expense | $29,418 | $21,256 | $87,053 | $63,430 |
| Other operating (income) expense | $(23,363) | $(57,287) | $(110,467) | $(55,172) |
| Interest expense | $46,275 | $45,637 | $146,102 | $128,850 |
| Price risk management activities (income) expense | $(126,291) | $98,802 | $(41,531) | $13,668 |
| Equity method investment (income) expense | $544 | $2,493 | $9,054 | $(2,938) |
| Other (income) expense | $(3,267) | $(2,193) | $48,465 | $(10,450) |
| Income tax (benefit) expense | $18,111 | $(15,865) | $(4,445) | $(55,516) |

### Three Months Ended September 30, 2024 and 2023 —

***Accretion Expense —*** During the three months ended September 30, 2024, we recorded $29.4 million of accretion expense compared to $21.3 million during the three months ended September 30, 2023. The change is primarily the result of a $4.6 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

***Other Operating (Income) Expense —*** During the three months ended September 30, 2024, other operating (income) expense primarily reflects an incremental $13.5 million gain on the TLCS Divestiture due to the recognition of contingent consideration as well as a $7.0 million increase in fair value of a service credit acquired via the QuarterNorth Acquisition. During the three months ended September 30, 2023, we recognized a gain of $66.2 million related to the deconsolidation of Talos Mexico (as defined below) partially offset by $8.0 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.

***Price Risk Management Activities —*** The income of $126.3 million for the three months ended September 30, 2024 consists of $120.2 million in non-cash gains from the increase in the fair value of our open derivative contracts and $6.1 million in cash settlement gains. The expense of $98.8 million for the three months ended September 30, 2023 consists of $92.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $6.3 million in cash settlement losses.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each reporting period. As a result of the derivative contracts we have on our anticipated production volumes through December 2025, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments.”*

***Income Tax (Benefit) Expense —*** During the three months ended September 30, 2024, we recorded $18.1 million of income tax expense compared to $15.9 million of income tax benefit during the three months ended September 30, 2023. The income tax expense recorded during the three months ended September 30, 2024 is primarily due to current year activity offset by the impact from permanent differences. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 — *Income Taxes.”*

### Nine Months Ended September 30, 2024 and 2023 —

***Accretion Expense —*** During the nine months ended September 30, 2024, we recorded $87.1 million of accretion expense compared to $63.4 million during the nine months ended September 30, 2023. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of both the EnVen Acquisition and QuarterNorth Acquisition and upward revisions of our asset retirement obligations. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

***Other Operating (Income) Expense —*** During the nine months ended September 30, 2024, we recognized a gain of $100.4 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for further discussion. During the nine months ended September 30, 2023, we recognized a gain of $66.2 million related to the deconsolidation of Talos Mexico partially offset by $9.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.

***Interest Expense —*** During the nine months ended September 30, 2024, we recorded $146.1 million of interest expense compared to $128.9 million during the nine months ended September 30, 2023. The change is primarily the result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

***Price Risk Management Activities —*** The income of $41.5 million for the nine months ended September 30, 2024 consists of $56.5 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $14.9 million in cash settlement losses. The expense of $13.7 million for the nine months ended September 30, 2023 consists of $3.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $10.5 million in cash settlement losses.

***Equity Method Investment (Income) Expense —*** During the nine months ended September 30, 2024, we recorded equity losses of $9.1 million. During the nine months ended September 30, 2023, we recorded an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend CCS LLC (“Bayou Bend”) by Chevron U.S.A. Inc. (“Chevron”) offset by equity losses of $5.6 million.

***Other (Income) Expense —*** During the nine months ended September 30, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***Income Tax (Benefit) Expense —*** During the nine months ended September 30, 2024, we recorded $4.4 million of income tax benefit compared to $55.5 million of income tax benefit during the nine months ended September 30, 2023. The income tax benefit is primarily due to current year activity offset by the impact from permanent differences and a non-cash income tax benefit recognized in the Company’s state deferred tax liability. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 — *Income Taxes.”*

### Supplemental Non-GAAP Measure

### EBITDA and Adjusted EBITDA

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

We define these as the following:

- ***EBITDA —*** Net income (loss) plus interest expense, income tax 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, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.

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

|  | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Net income (loss) | $88,173 | $(2,103) | $(11,885) | $101,434 |
| Interest expense | 46,275 | 45,637 | 146,102 | 128,850 |
| Income tax (benefit) expense | 18,111 | (15,865) | (4,445) | (55,516) |
| Depreciation, depletion and amortization | 274,249 | 163,359 | 749,004 | 480,476 |
| Accretion expense | 29,418 | 21,256 | 87,053 | 63,430 |
| EBITDA | 456,226 | 212,284 | 965,829 | 718,674 |
| Transaction and other (income) expenses(1) | (17,687) | (64,321) | (60,215) | (38,799) |
| Decommissioning obligations(2) | 2,725 | 7,972 | 7,762 | 9,454 |
| Derivative fair value (gain) loss(3) | (126,291) | 98,802 | (41,531) | 13,668 |
| Net cash received (paid) on settled derivative instruments(3) | 6,071 | (6,313) | (14,941) | (10,474) |
| (Gain) loss on debt extinguishment | — | — | 60,256 | — |
| Non-cash equity-based compensation expense | 3,315 | 393 | 8,859 | 9,080 |
| Adjusted EBITDA | $324,359 | $248,817 | $926,019 | $701,603 |

(1) For the three months ended September 30, 2024, transaction expenses include $4.7 million in severance expense related to the departure of the Company’s former President and Chief Executive Officer as discussed in Part I, Item 1. “Financial Statements — Note 9 — *Employee Benefits Plans and Share-Based Compensation.”* For the nine months ended September 30, 2024, transaction expenses include $38.8 million in costs related to the QuarterNorth Acquisition, inclusive of $22.3 million in severance expense, and $8.4 million in costs related to the TLCS Divestiture, inclusive of a net $2.9 million in severance expense. For the three and nine months ended September 30, 2023, transaction expenses included $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* and “Note 9 — *Employee Benefits Plans and Share-Based Compensation.”* Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2024, it includes a gain of $13.5 million and $100.4 million related to the TLCS Divestiture, respectively. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”* Additionally, for the three and nine months ended September 30, 2024, it includes a gain of $7.0 million and $9.5 million, respectively, related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain related to the deconsolidation of Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”). For the nine months ended September 30, 2023, the amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million.

(2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 13 — *Commitments and Contingencies”* for additional information on decommissioning obligations.

(3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

### Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility (as defined herein). Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of September 30, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $842.9 million.

We fund our development and exploration activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through equity issuances. We adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

Our liquidity could be impacted in the future by financial assurance requirements. See “Known Trends and Uncertainties — BOEM Bonding Rule.”

***Capital Expenditures —*** The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2024 (in thousands):

|  |  |
| --- | ---: |
| U.S. drilling & completions | $185,320 |
| Asset management(1) | 96,034 |
| Seismic and G&G, land, capitalized G&A and other | 72,817 |
| Total Upstream capital expenditures | 354,171 |
| Plugging & abandonment | 86,074 |
| Decommissioning obligations settled(2) | 5,094 |
| Investment in Mexico | 2,108 |
| Total Upstream | 447,447 |
| Investment in CCS | 17,519 |
| Total | $464,966 |

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

(2) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 13 — *Commitments and Contingencies.”*

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2024 Upstream capital spending program of $510.0 million to $530.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $110.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

***Common Stock Repurchase Program —*** Our Board authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In July 2024, our Board authorized an increase of $150.0 million to the previously approved limit increasing the amount remaining under the authorized plan to $159.7 million. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program. We do not currently anticipate incurring any excise tax in 2024 based on the fair market value of the common stock issued during 2024.

During the nine months ended September 30, 2024, we repurchased approximately 4.0 million shares for $45.1 million. As of September 30, 2024, there is $157.5 million remaining under the authorized program. See Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information on repurchases made during the three months ended September 30, 2024.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

***Overview of Cash Flow Activities —*** The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

|  | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: |
| Operating activities | $613,256 | $342,811 |
| Investing activities | $(1,168,024) | $(391,874) |
| Financing activities | $569,714 | $120,309 |

***Operating Activities —*** Net cash provided by operating activities increased $270.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $245.7 million.

***Investing Activities —*** Net cash used in investing activities increased $776.2 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily due to cash paid for acquisitions of $936.2 million, net of cash acquired, of which $916.0 million related to the QuarterNorth Acquisition. Cash proceeds of $142.0 million was received from the TLCS Divestiture during the nine months ended September 30, 2024 compared to $66.2 million of net proceeds from the sale of property and equipment during the corresponding period in 2023. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $83.3 million.

***Financing Activities —*** Cash flow from financing activities changed $449.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023. During the nine months ended September 30, 2024, the issuance of the New Senior Notes in February 2024 generated $1,220.1 million after deferred financing costs. The net proceeds from the New Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for additional information. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, Bank Credit Facility net repayments of $75.0 million were made during the nine months ended September 30, 2024 due to a management goal to maintain or reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. We had net borrowings from the Bank Credit Facility of $215.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.

### Overview of Debt Instruments

***9.000% Second-Priority Senior Secured Notes — due February 2029 —*** The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***9.375% Second-Priority Senior Secured Notes — due February 2031 —*** The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***Bank Credit Facility — matures March 2027 —*** We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that the Company delivers to the administrative agent of our Bank Credit Facility. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***Redemption of the 12.00% Second-Priority Senior Secured Notes — due January 2026 —*** On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

***Redemption of the 11.75% Senior Secured Second Lien Notes — due April 2026 —*** On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for more information.

### Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements.

The following table and discussion summarize our material cash requirements from known contractual obligations as of September 30, 2024 (in thousands):

| Long-term financing obligations: | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total(5) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Debt principal | $— | $— | $— | $125,000 | $— | $1,250,000 | $1,375,000 |
| Debt interest | 10,633 | 129,021 | 129,021 | 118,388 | 114,844 | 174,609 | 676,516 |
| Vessel commitments(1) | 31,950 | 97,269 | — | — | — | — | 129,219 |
| Derivative liabilities | 3,723 | 1,412 | — | — | — | — | 5,135 |
| Operating lease obligations | 2,995 | 5,656 | 4,983 | 4,753 | 4,610 | 4,584 | 27,581 |
| Finance lease(2) | 11,826 | 19,711 | — | — | — | — | 31,537 |
| Purchase obligations(3) | 40,700 | 3,271 | — | — | — | — | 43,971 |
| Other commitments(4) | 7,658 | 19,826 | 16,511 | 9,249 | 10,619 | 5,918 | 69,781 |
| Total contractual obligations(5) | $109,485 | $276,166 | $150,515 | $257,390 | $130,073 | $1,435,111 | $2,358,740 |

(1) Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.

(2) Lease agreement for the HP-I floating production facility we utilize to produce the Phoenix Field.

(3) Includes committed purchase orders to execute planned future oil and natural gas operational activities.

(4) Includes firm transportation commitments as further discussed under Part I, Item 1. “Financial Statements — Note 13 — *Commitments and Contingencies”* and deferred payments related to our acquisition of working interests in the Monument oil discovery as further discussed under Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

(5) This table does not include our estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties with a carrying value of $1,189.9 million as of September 30, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 — *Asset Retirement Obligations.”* Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 13 — *Commitments and Contingencies.”*

***Performance Obligations —*** As of September 30, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.7 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 7 — *Debt”* for further information on the Bank Credit Facility.

### Critical Accounting Estimates

There have been no changes to our critical accounting estimates from those disclosed in our 2023 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

### Recently Adopted Accounting Standards

None.

### Recently Issued Accounting Standards

No accounting standards were issued during the quarterly period ended September 30, 2024 that were material to us.

## Market risk

As filed, 1,504 characters.

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2023 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2023 Annual Report regarding our exposures to certain market risks.

### Price Risk Management Activities

We had commodity derivative instruments in place to reduce the price risk associated with future production of 13,270 MBbls of crude oil and 22,268 MMBtu of natural gas at September 30, 2024, with a net derivative asset position of $86.4 million. For additional information regarding our commodity derivative instruments, see Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments,”* included elsewhere in this Quarterly Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at September 30, 2024 (in thousands):

|  | Fair Value | Oil and Natural Gas Derivatives Ten Percent Increase Fair Value | Change | Ten Percent Decrease Fair Value | Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Price impact(1) | $86,368 | $(5,038) | $(91,406) | $178,875 | $92,507 |

(1) Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

## Controls and procedures

As filed, 6,136 characters.

### Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2024 as a result of the material weaknesses in our internal control over financial reporting described below.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. As previously reported in our Form 10-K/A for the year ended December 31, 2023, Form 10-Q/A for the fiscal quarter ended March 31, 2024, and Form 10-Q/A for the fiscal quarter ended June 30, 2024, each filed on the date hereof, subsequent to the end of the period covered by this Quarterly Report, we identified material weaknesses in our internal control over financial reporting.

In September 2024, the Company received a notification from a third party suggesting a mid-level employee (the “subject employee”) was engaged in inappropriate procurement practices. In response, the audit committee of the Company’s board of directors (the “Audit Committee”), conducted a review of such alleged practices by engaging independent external legal counsel to assist in reviewing the matter and determining the extent of such activities. Such review with external legal counsel did not identify nor implicate other current or former employees and the subject employee was separated from the Company. The Audit Committee also did not identify any related material errors in the Company’s historical financial statements.

However, in the course of its review, the Company identified two material weaknesses. The first material weakness identified was due to our inability to rely on the review control performed by the subject employee with respect to the estimated decommissioning costs incorporated into the asset retirement obligations recognized in our consolidated financial statements. As such, we could not rely on the subject employee’s judgment in the operation of the review control, which is performed upon acquisition of oil and gas assets subject to the retirement obligation and when costs are incurred and reassessed. Although the review of such costs was a task unrelated to the reported conduct subject to our review, we nevertheless determined that the concerns raised regarding the subject employee’s reliability made it inappropriate to have relied on such subject employee’s judgment in the review function. The second material weakness identified was due to inappropriate segregation of duties without designing and maintaining effective monitoring controls over the timely review of expenditures associated with asset retirement obligation spending, capital expenditures and lease operating expenses.

Notwithstanding the identified material weaknesses above, management has concluded that our condensed consolidated financial statements and related notes thereto included herein fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented.

### Plan for Remediation of Material Weaknesses

Management, with oversight from the Audit Committee, has developed a remediation plan to address the material weaknesses. The remediation plan includes, among other things:

- The separation of the subject employee from the Company.
- The appointment of qualified personnel over business processes related to the review of estimated decommissioning costs.
- The enhancement of policies and training relating to defined roles and responsibilities, the appropriate segregation of duties, and the promotion of ethical behavior.
- Establishing and enhancing the design, including the precision, of the monitoring control(s) related to expenditures associated with asset retirement obligation spending, capital expenditures and lease operating expenses, and the effective operation of such control(s).

We believe that these actions, collectively, will remediate the material weaknesses identified. However, we will not be able to conclude that we have completely remediated the material weaknesses until the applicable controls are fully implemented and operated for a sufficient period of time and management has concluded, through formal testing, that the remediated controls are operating effectively. We will continue to monitor the design and effectiveness of these and other processes, procedures, and controls and will make any further changes management deems appropriate.

### Internal Control over Financial Reporting

Except for the unremediated material weaknesses noted above, there were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2024 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 11,974 characters.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2023 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Other than set forth below, there have been no material changes in our risk factors from those described in our 2023 Annual Report or our other SEC filings.

***Our Rights Agreement includes terms and conditions that could discourage, delay or prevent a takeover or other transaction that some stockholders may consider favorable.***

On October 1, 2024, the Company entered into the Rights Agreement, pursuant to which the Board declared a dividend of one Right for each share of Common Stock outstanding at the close of business on October 11, 2024. Each Right initially entitles the registered holder, subject to the terms of the Rights Agreement, to purchase from the Company one one-thousandth of a Preferred Share for $62.10, subject to adjustment under certain conditions. In general terms, Rights will become exercisable only if a person or group acquires 25% or more of our outstanding Common Stock. If Rights become exercisable, all holders of Rights (other than the person or group triggering the Rights Agreement, whose rights will become void and will not be exercisable) will have the right, pursuant to the terms of the Rights Agreement, to purchase from the Company for $62.10, subject to certain potential adjustments, shares of our Common Stock having an aggregate market value of twice that amount. The Rights expire at the earlier of (i) October 1, 2027 and (ii) October 1, 2025 if Stockholder Approval (as defined in the Rights Agreement) has not been received prior to such time, unless such date is advanced or extended or unless the Rights are earlier redeemed or exchanged by the Board as permitted in the Rights Agreement. Additional information regarding the Rights Agreement is contained in the Current Report on Form 8-K filed with the SEC on October 1, 2024 and the Rights Agreement is filed at Exhibit 4.11 to this Quarterly Report.

In general terms, the Rights Agreement will cause substantial dilution to any person or group that acquires beneficial ownership of 25% or more of the Company’s outstanding Common Stock without the approval of the Board. As a result, the overall effect of the Rights Agreement and the issuance of the Rights may be to discourage any person, entity or group from gaining a control or control-like position in the Company or engaging in other tactics, potentially disadvantaging the interests of the Company’s stockholders, without negotiating with the Board and without paying an appropriate control premium to all stockholders. The Rights Agreement is similar to plans adopted by other public companies and is intended to help protect stockholders’ interests, including protecting stockholders from any efforts at negative control. Further, the Rights Agreement is intended to position the Board to fulfill its duties by providing sufficient time for the Board to make informed judgments and take actions that are in the best interests of the Company and its stockholders. Nevertheless, the Rights Agreement may be considered to have certain anti-takeover effects, including potentially discouraging, delaying or preventing a change of control of the Company or a takeover attempt, even if such actions may be considered beneficial or favorable by some stockholders. Even in the absence of a takeover attempt, the Rights Agreement may adversely affect the prevailing market price of our Common Stock if it is viewed as discouraging takeover attempts in the future.

***Actions of activist stockholders or others could materially and adversely affect our business, results of operations and stock price.***

We may become subject to actions or proposals from stockholders or others that may not align with our business strategies or the interests of our other stockholders. Responding to such actions can be costly and time-consuming, disrupt our business and operations, and divert the attention of the Board, management, and employees from the pursuit of our business strategies. Such activities could interfere with our ability to execute our strategic plan. Activist stockholders or others may create perceived uncertainties as to the future direction of our business or strategy which may be exploited by our competitors and may make it more difficult to attract and retain qualified personnel and potential customers, and may affect our relationships with current customers, vendors, investors and other third parties. In addition, a proxy contest for the election of directors at an annual meeting would require us to incur significant legal fees and proxy solicitation expenses and require significant time and attention by management and our Board. Our stock price could also be subject to significant fluctuations or otherwise be adversely affected by the events, risks and uncertainties of any stockholder activism.

***Changes in U.S. trade policy, including the imposition of tariffs and the resulting consequences, could adversely affect our business, prospects, financial condition and operating results.***

There is currently significant uncertainty about the future relationship between the United States and various other countries, including changes arising as a result of any change in administration due to the upcoming U.S. presidential election with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements could have an adverse effect on our business, prospects, financial condition and operating results, the extent of which cannot be predicted with certainty at this time.

***Recent and pending management changes could disrupt our operations and impair our ability to attract and retain key personnel.***

We have experienced recent changes to our senior management team, including the departure of our President and Chief Executive Officer on August 29, 2024. Joseph A. Mills will serve as Interim Chief Executive Officer and President, effective as of August 29, 2024 while our Board conducts a search for a permanent Chief Executive Officer. Changes in our senior management and uncertainty regarding pending changes may disrupt our operations, impact customer and partner relationships, and impair our ability to recruit and retain other needed personnel. Any such disruption or impairment could have an adverse effect on our business.

***We have identified material weaknesses in our internal control over financial reporting that could, if not remediated, result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.***

As more fully disclosed in this Form 10-Q under Part I, Item 4. “Controls and Procedures,” our Audit Committee, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures and internal control over financial reporting as of September 30, 2024. Based on that evaluation, we concluded that our disclosure controls and procedures were not effective as of September 30, 2024 due to material weaknesses identified in our internal control over financial reporting.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

In September 2024, the Company received a notification from a third party suggesting that the subject employee was engaged in inappropriate procurement practices. In response, the Audit Committee conducted a review of such alleged practices by engaging independent external legal counsel to assist in reviewing the matter and determining the extent of such activities. Such review with external legal counsel did not identify nor implicate other current or former employees and the subject employee was separated from the Company. The Audit Committee also did not identify any related material errors in the Company’s historical financial statements.

However, in the course of its review, the Company identified two material weaknesses. The first material weakness identified was due to our inability to rely on the review control performed by the subject employee with respect to the estimated decommissioning costs incorporated into the asset retirement obligations recognized in our consolidated financial statements. As such, we could not rely on the subject employee’s judgment in the operation of the review control, which is performed upon acquisition of oil and gas assets subject to the retirement obligation and when costs are incurred and reassessed. Although the review of such costs was a task unrelated to the reported conduct subject to our review, we nevertheless determined that the concerns raised regarding the subject employee’s reliability made it inappropriate to have relied on such subject employee’s judgment in the review function. The second material weakness identified was due to inappropriate segregation of duties without designing and maintaining effective monitoring controls over the timely review of expenditures associated with asset retirement obligation spending, capital expenditures and lease operating expenses.

While these material weaknesses did not result in a material misstatement of our consolidated financial statements, these internal control deficiencies were not remediated as of September 30, 2024 and there is a reasonable possibility that it could have resulted in a material misstatement in the Company's annual or interim consolidated financial statements that would not have been detected. Accordingly, we have determined that these internal control deficiencies constituted material weaknesses in our internal control over financial reporting. While management, under the oversight of our Audit Committee, has taken steps to implement our remediation plan as described more fully in Part I, Item 4. “Controls and Procedures” of this Form 10-Q, the material weaknesses described above will not be considered remediated until the enhanced controls operate for a sufficient period of time and management has concluded, through testing, that the related controls are effective. Furthermore, we can give no assurance that the measures we take will remediate the material weaknesses.

We can give no assurance that additional material weaknesses will not arise in the future. Any failure to remediate these material weaknesses, or the development of any new material weaknesses in our internal control over financial reporting, could result in material misstatements in our consolidated financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition, results of operations or cash flows, restrict our ability to access the capital markets, require significant resources to correct the material weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in both investor confidence and the market price of our stock.

Filed Nov 12, 2024.
Source: SEC EDGAR, the filing index for accession 0000950170-24-125580. Last ingested by Listed: Nov 3, 2026, 21:34 ET. No prices; not investment advice.