Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless otherwise indicated or the context requires otherwise, references in this Quarterly Report to “us,” “we,” “our,” “Talos,” or the “Company” refer to Talos Energy Inc. and its subsidiaries. References to “Parent Company” refer to Talos Energy Inc.
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 2025 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 2025 Annual Report.
Our Business
We are a technically driven, innovative, independent energy company focused on safely maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America 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.
We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and reserve recovery, safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.
Operational Update
The following encompasses recent operational updates since the filing of our Quarterly Report on Form 10-Q for the three months ended June 30, 2026.
CPN — We achieved first oil at the CPN well (“CPN”) in late September 2026. We are the operator of CPN and hold a 65% working interest.
Monument — The second development well in the Monument oil discovery (“Monument”) was spud in early September 2026, later than previously anticipated, after the operator redeployed the rig to another asset in which we do not hold a working interest before returning the rig to Monument. Completion operations on both development wells are expected to commence after the second well reaches target depth. First oil from Monument is now expected in the first quarter of 2027. We hold a 29.7% non-operated working interest in Monument.
Brutus Program — The development program at our Brutus Field (“Brutus Program”) commenced during the third quarter with operations from the platform-based rig. First oil from the Brutus Program is expected to be phased from the second quarter through the fourth quarter of 2027. The Brutus Program has also expanded from four to five wells to include an additional sidetrack opportunity.
Daenerys — The appraisal well at our Daenerys discovery (“Daenerys”) was spud in early July 2026 and successfully reached its target depth in late August 2026. We expect to conduct further appraisal activity at Daenerys in 2027, including a sidetrack designed to further evaluate the discovery. We also expect to drill an exploration well in late 2027 targeting a prospect near Daenerys that we acquired in the December 2025 Big Beautiful Gulf 1 lease sale.
Offshore Honduras — We commenced the 3D seismic campaign in October 2026, initially targeting a portion of the deepwater acreage.
Recent Developments
The following encompasses recent developments since the filing of our Quarterly Report on Form 10-Q for the three months ended June 30, 2026.
Closing of the Coulomb and Na Kika Acquisition — On September 22, 2026, we closed on the acquisition of certain oil and gas properties and related assets in the Mississippi Canyon area of the U.S. Gulf of America, including interests in the Coulomb and Na Kika Deepwater producing assets (the “Coulomb and Na Kika Acquisition”) from Shell Offshore Inc. (“Shell”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.
Credit Facility Updates — In connection with the closing of the Coulomb and Na Kika Acquisition, the borrowing base under our bank credit facility increased from $700.0 million to $850.0 million, and the letter of credit sublimit increased from $250.0 million to $300.0 million. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
Share Repurchase Program — During the three months ended September 30, 2026, we repurchased approximately 1.4 million shares for $23.6 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors (the “Board”), resulting in $176.4 million available under the share repurchase program as of September 30, 2026. See “Liquidity and Capital Resources — Share Repurchase Program” for additional information.
Factors Affecting the Comparability of our Financial Condition and Results of Operations
No material events, such as acquisitions or divestitures, affected the comparability of our financial condition or results of operations for the periods presented herein other than the Coulomb and Na Kika Acquisition and the debt refinancing discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” and Part I, Item 1. “Financial Statements — Note 7 — Debt,” respectively. Management does not currently expect any material factors to affect the comparability of our future financial condition or results of operations, other than the Coulomb and Na Kika Acquisition and the debt refinancing.
Known Trends and Uncertainties
Except as discussed below, there have been no material developments to known trends and uncertainties discussed in our 2025 Annual Report:
Volatility in Oil, Natural Gas and NGL Prices — Oil, natural gas, and NGL prices have been, and are expected to continue to be, volatile. The war in Iran, which began in February 2026, has increased geopolitical risk in global energy markets and contributed to volatility in oil and gas prices. The war has also disrupted, and could further disrupt, maritime transit, supply chains, and energy infrastructure throughout the Middle East and adjacent waters, including along major shipping routes and chokepoints such as the Strait of Hormuz, a critical route for global oil and liquefied natural gas shipments. The duration and extent of these disruptions, and the timing and extent of any normalization of production, exports, transportation networks, and related supply chains, remain uncertain. Any continuation or further escalation of geopolitical tensions, or continued or increased disruptions to trade routes, supply chains, or energy infrastructure, could affect global supply-demand balances and contribute to further volatility in commodity prices. Such volatility could also affect customer demand, counterparty credit risk and broader macroeconomic conditions. We cannot predict the nature, timing or magnitude of any future effects on our business, financial condition or results of operations.
Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices. We use hedging instruments as part of our risk management strategy to reduce the impact of near-term price volatility, mitigate downside exposure, and allow for participation in favorable commodity price movements during periods of higher prices. We also anticipate continuing to operate our business in a volatile market by prioritizing high-return development projects, focusing on cost control measures, and maintaining a strong balance sheet to provide financial, operational and capital spending flexibility under a range of price scenarios. We continue to monitor commodity price trends closely and will modify our plans within our strategy as appropriate. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of September 30, 2026.
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 for any commodity that we produce will generally approximate current market prices in the geographic region of production.
Inflation of Cost of Goods, Services and Personnel — The war in Iran triggered inflationary pressures in the global economy. In September 2026, the U.S. Federal Reserve raised its benchmark federal funds rate by a quarter of a percentage point to a range of 3.75% to 4.00%. Future changes to the benchmark interest rate remain uncertain.
Impact of Prolonged Increases in Tariffs —We continue to monitor changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. The imposition of additional or any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2026 and beyond.
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. No impairment was recorded during the three months ended September 30, 2026. However, as a result of our ceiling test computations, an impairment of our U.S. oil and natural gas properties was recorded during the nine months ended September 30, 2026 of $145.0 million. At September 30, 2026 our ceiling test computation was based on SEC pricing of $75.79 per Bbl of oil, $3.87 per Mcf of natural gas and $20.35 per Bbl of NGLs. During the three and nine months ended September 30, 2025, we recorded an impairment of $60.2 million and $284.1 million, respectively. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment” for additional information.
Because the ceiling calculation uses trailing twelve-month first day of the month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects. Depending on fluctuations in these factors, including price changes, we may incur ceiling test impairments in future quarters.
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 2025 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, 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.
Financial Assurance Rule Update — On March 9, 2026, BOEM published a new proposed rule entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” The proposed rule reverts to BOEM’s former policy of considering the financial strength of co-owners and predecessors in title when determining whether supplemental financial assurance is required, and revises the credit rating threshold used for evaluating the financial health of lessees and grantees from BBB- to BB- (S&P Global Ratings) or Baa3 to Ba3 (Moody’s Investor Service Inc.). MMA (the new bureau combining BOEM and BSEE), however, retains the discretion to require financial assurance and/or issue liability orders where appropriate, including if it determines there is a substantial risk of nonperformance of an interest holder’s decommissioning liabilities for which the predecessor is not liable.
While we anticipate that MMA’s proposed rule, if finalized in its current form, would reduce the amount of financial assurance required from certain lessees as compared to the previous rule, the final version and timing of adoption of MMA’s proposed rule remain uncertain. Any future requirements to provide additional or replacement financial assurances under future regulatory actions or rules could require significant use of our capital or restrict liquidity and could materially and adversely affect our financial condition, cash flows, liquidity, and results of operations.
See Part I, Items 1 and 2. “Business and Properties — Government Regulation — BOEM Financial Assurance Requirements” and Part I, Item 1A. “Risk Factors — We may not be able to obtain sufficient surety bonds on reasonably acceptable terms to conduct our business” in our 2025 Annual Report for further background on BOEM’s financial assurance requirements.
Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion — In August 2024, the federal district court for the District of Maryland vacated the 2020 Biological Opinion issued by the National Marine Fisheries Service (“NMFS”), related to oil and gas activities in the Gulf of America. On May 20, 2025, NMFS published a new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. Two lawsuits were filed opposing the new Biological Opinion, one by several environmental groups (Sierra Club, the Center for Biological Diversity, Friends of the Earth and Turtle Island Restoration Network) who filed in the federal district court for the District of Maryland, and the other by the State of Louisiana, the American Petroleum Institute and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. On February 20, 2026, the Western Louisiana District Court remanded without vacatur NMFS’ 2025 Biological Opinion, declaring that the Rice’s whale jeopardy finding and the Reasonable and Prudent Alternative are arbitrary, capricious and contrary to law. NMFS was required to complete the remand within 185 days of the Western Louisiana District Court’s order. As a result of the remand, the intervenors in the lawsuit filed in the District of Maryland sought to stay the litigation pending completion of the remand order. On March 31, 2026, the Endangered Species Committee (“ESC”), comprised of the Secretary of the Interior, the Secretary of Agriculture, the Secretary of the Army, the Chair of the Council of Economic Advisers, the Administrator of the Environmental Protection Agency, and the Administrator of the National Oceanic and Atmospheric Administration, held a public meeting to address the Secretary of War’s national security finding that it was necessary to exempt Gulf of America oil and gas activities from requirements of the Endangered Species Act. By unanimous vote, the ESC exempted oil and gas activities in the Gulf of America from Section 7 consultation and Section 7(a)(2) requirements pursuant to Section 7(h) of the Endangered Species Act. On June 24, 2026, the District of Maryland’s federal district court judge issued a decision from the bench to dismiss the challenge to the 2025 Biological Opinion on the basis that it is moot given the ESC’s exemption decision. On the same day, the Maryland court judge issued a written order dismissing the plaintiffs’ case without prejudice for lack of subject-matter jurisdiction. Several separate lawsuits have been filed challenging the ESC’s exemption decision and the underlying national security finding. At this time, the ultimate impact of the ESC decision is uncertain.
See Part II, Item 1A. “Risk Factors” of this Quarterly Report and Part II, Item 1A. “Risk Factors” in our 2025 Annual Report for additional information regarding our risk factors.
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 (in thousands, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended September 30, |
|
|
|
|
2026 |
|
2025 |
|
Change |
|
2026 |
|
2025 |
|
Change |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
$ |
549,800 |
|
$ |
400,210 |
|
$ |
149,590 |
|
$ |
1,578,566 |
|
$ |
1,214,128 |
|
$ |
364,438 |
|
Natural gas |
|
32,139 |
|
|
41,306 |
|
|
(9,167 |
) |
|
116,082 |
|
|
133,456 |
|
|
(17,374 |
) |
NGL |
|
14,052 |
|
|
8,537 |
|
|
5,515 |
|
|
38,466 |
|
|
40,249 |
|
|
(1,783 |
) |
Total revenues |
$ |
595,991 |
|
$ |
450,053 |
|
$ |
145,938 |
|
$ |
1,733,114 |
|
$ |
1,387,833 |
|
$ |
345,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
6,306 |
|
|
6,127 |
|
|
179 |
|
|
18,287 |
|
|
18,095 |
|
|
192 |
|
Natural gas (MMcf) |
|
8,625 |
|
|
12,606 |
|
|
(3,981 |
) |
|
28,117 |
|
|
36,626 |
|
|
(8,509 |
) |
NGL (MBbls) |
|
671 |
|
|
529 |
|
|
142 |
|
|
1,965 |
|
|
2,132 |
|
|
(167 |
) |
Total production volume (MBoe) |
|
8,415 |
|
|
8,757 |
|
|
(342 |
) |
|
24,938 |
|
|
26,331 |
|
|
(1,393 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Production Volumes by Product: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBblpd) |
|
68.5 |
|
|
66.6 |
|
|
1.9 |
|
|
67.0 |
|
|
66.3 |
|
|
0.7 |
|
Natural gas (MMcfpd) |
|
93.8 |
|
|
137.0 |
|
|
(43.2 |
) |
|
103.0 |
|
|
134.2 |
|
|
(31.2 |
) |
NGL (MBblpd) |
|
7.3 |
|
|
5.8 |
|
|
1.5 |
|
|
7.2 |
|
|
7.8 |
|
|
(0.6 |
) |
Total production volume (MBoepd) |
|
91.5 |
|
|
95.2 |
|
|
(3.7 |
) |
|
91.3 |
|
|
96.5 |
|
|
(5.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sale Price Per Unit: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
87.19 |
|
$ |
65.32 |
|
$ |
21.87 |
|
$ |
86.32 |
|
$ |
67.10 |
|
$ |
19.22 |
|
Natural gas (per Mcf) |
$ |
3.73 |
|
$ |
3.28 |
|
$ |
0.45 |
|
$ |
4.13 |
|
$ |
3.64 |
|
$ |
0.49 |
|
NGL (per Bbl) |
$ |
20.94 |
|
$ |
16.14 |
|
$ |
4.80 |
|
$ |
19.58 |
|
$ |
18.88 |
|
$ |
0.70 |
|
Price per Boe |
$ |
70.82 |
|
$ |
51.39 |
|
$ |
19.43 |
|
$ |
69.50 |
|
$ |
52.71 |
|
$ |
16.79 |
|
Price per Boe (including realized commodity derivatives) |
$ |
67.28 |
|
$ |
53.29 |
|
$ |
13.99 |
|
$ |
64.43 |
|
$ |
54.80 |
|
$ |
9.63 |
|
The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sales prices and production volumes (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2026 vs 2025 |
|
Nine Months Ended September 30, 2026 vs 2025 |
|
|
Price |
|
Volume |
|
Total |
|
Price |
|
Volume |
|
Total |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
$ |
137,898 |
|
$ |
11,692 |
|
$ |
149,590 |
|
$ |
351,555 |
|
$ |
12,883 |
|
$ |
364,438 |
|
Natural gas |
|
3,891 |
|
|
(13,058 |
) |
|
(9,167 |
) |
|
13,599 |
|
|
(30,973 |
) |
|
(17,374 |
) |
NGL |
|
3,223 |
|
|
2,292 |
|
|
5,515 |
|
|
1,370 |
|
|
(3,153 |
) |
|
(1,783 |
) |
Total revenues |
$ |
145,012 |
|
$ |
926 |
|
$ |
145,938 |
|
$ |
366,524 |
|
$ |
(21,243 |
) |
$ |
345,281 |
|
Three Months Ended September 30, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 3.7 MBoepd to 91.5 MBoepd. This decrease is primarily attributable to 3.1 MBoepd in production related to the divestiture of a wholly-owned subsidiary that held non-core, gas-weighted and predominantly non-operated Shelf and Gulf Coast properties (the “Shelf and Gulf Coast Divestiture”) compared to the same period in 2025. Additionally, there was a 2.8 MBoepd decline at the Brutus Field, primarily driven by a high-rate gas recompletion, where the well has declined as expected and will be sidetracked to a deeper target in the ongoing Brutus Program. These decreases were partially offset by an increase of 3.0 MBoepd related to incremental production at our Sunspear Field.
Nine Months Ended September 30, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 5.2 MBoepd to 91.3 MBoepd. This decrease is primarily attributable to a 4.2 MBoepd decline at the Brutus Field, driven by factors mentioned above, as well as 1.7 MBoepd in production related to the Shelf and Gulf Coast Divestiture compared to the same period in 2025. These decreases were partially offset by an increase of 3.6 MBoepd related to incremental production at our Sunspear 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, |
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
|
Lease operating expenses |
$ |
140,856 |
|
$ |
133,718 |
|
$ |
425,574 |
|
$ |
398,494 |
|
Lease operating expenses per Boe |
$ |
16.74 |
|
$ |
15.27 |
|
$ |
17.07 |
|
$ |
15.13 |
|
Three Months Ended September 30, 2026 and 2025 — Lease operating expense for the three months ended September 30, 2026 increased by approximately $7.1 million, or 5%, primarily due to higher direct operating expenses associated with non-operated properties. The increase was partially offset by lower non-recurring project costs.
Nine Months Ended September 30, 2026 and 2025 — Lease operating expense for the nine months ended September 30, 2026 increased by approximately $27.1 million, or 7%. This was primarily due to an increase in major well workover expenses at the Galapagos Field to return the Genovesa well to production compared to the same period in 2025.
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, |
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
|
Depreciation, depletion and amortization |
$ |
233,430 |
|
$ |
262,637 |
|
$ |
693,183 |
|
$ |
813,059 |
|
Three Months Ended September 30, 2026 and 2025 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2026 decreased by approximately $29.2 million, or 11%. This decrease was primarily driven by a decrease of $2.23, or 7%, in the depletion rate on our proved oil and natural gas properties, as well as decreased production volumes of 3.7 MBoepd discussed above. The change in DD&A rate and decreased production volumes between periods caused DD&A expense to decrease by $18.8 million and $10.3 million, respectively.
Nine Months Ended September 30, 2026 and 2025 — DD&A expense for the nine months ended September 30, 2026 decreased by approximately $119.9 million, or 15%. This decrease was primarily driven by a decrease of $3.07, or 10%, in the depletion rate on our proved oil and natural gas properties, as well as decreased production volumes of 5.2 MBoepd discussed above. The change in DD&A rate and decreased production volumes between periods caused DD&A expense to decrease by $76.6 million and $42.9 million, respectively. The decrease in the DD&A rate was primarily attributable to a lower amortization base resulting from impairment charges recorded in prior periods.
General and Administrative Expense
The following table highlights general and administrative 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, |
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
|
General and administrative expense |
$ |
43,143 |
|
$ |
41,547 |
|
$ |
128,739 |
|
$ |
115,592 |
|
General and administrative expense per Boe |
$ |
5.13 |
|
$ |
4.74 |
|
$ |
5.16 |
|
$ |
4.39 |
|
Three Months Ended September 30, 2026 and 2025 — General and administrative expense was relatively flat for the three months ended September 30, 2026.
Nine Months Ended September 30, 2026 and 2025 — General and administrative expense for the nine months ended September 30, 2026 increased by approximately $13.1 million, or 11%, primarily driven by higher employee related costs compared to the same period in 2025.
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, |
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
|
Accretion expense |
$ |
33,160 |
|
$ |
30,764 |
|
$ |
104,007 |
|
$ |
93,704 |
|
Impairment of oil and natural gas properties |
$ |
— |
|
$ |
60,209 |
|
$ |
145,018 |
|
$ |
284,090 |
|
Other operating (income) expense |
$ |
(11,574 |
) |
$ |
7,272 |
|
$ |
675 |
|
$ |
(1,115 |
) |
Interest expense |
$ |
40,194 |
|
$ |
40,847 |
|
$ |
118,534 |
|
$ |
122,585 |
|
Price risk management activities (income) expense |
$ |
120,576 |
|
$ |
(4,226 |
) |
$ |
263,574 |
|
$ |
(75,228 |
) |
Equity method investment (income) expense |
$ |
65 |
|
$ |
(639 |
) |
$ |
(6,492 |
) |
$ |
37 |
|
Other (income) expense |
$ |
30,051 |
|
$ |
(2,051 |
) |
$ |
20,636 |
|
$ |
(11,282 |
) |
Income tax (benefit) expense |
$ |
47,111 |
|
$ |
(24,204 |
) |
$ |
26,656 |
|
$ |
(60,721 |
) |
Three Months Ended September 30, 2026 and 2025 —
Impairment of oil and natural gas properties — During the three months ended September 30, 2026, we did not record an impairment of our oil and natural gas properties. During the three months ended September 30, 2025, we recorded a $60.2 million impairment of our oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” for additional information.
Other Operating (Income) Expense — During the three months ended September 30, 2026, we recorded income of $15.1 million related to multi-year federal royalty refund claims partially offset by a $3.0 million accrual related to a court judgment in a lawsuit. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information regarding the lawsuit.
Price Risk Management Activities — The expense of $120.6 million for the three months ended September 30, 2026 consists of $90.7 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $29.8 million in cash settlement losses. The income of $4.2 million for the three months ended September 30, 2025 consists of $16.6 million in cash settlement gains partially offset by $12.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts.
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 2027, 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.”
Other (Income) Expense — During the three months ended September 30, 2026, we recorded a $37.4 million loss on extinguishment of debt in conjunction with the redemption of the 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”). See Part I, Item 1. “Financial Statements — Note 7 – Debt” for more information.
Income Tax (Benefit) Expense — During the three months ended September 30, 2026, we recorded $47.1 million of income tax expense compared to $24.2 million of income tax benefit during the three months ended September 30, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.
Nine Months Ended September 30, 2026 and 2025 —
Accretion Expense — During the nine months ended September 30, 2026, we recorded $104.0 million of accretion expense compared to $93.7 million during the nine months ended September 30, 2025. The change is primarily due to a higher balance subject to accretion for the nine months ended September 30, 2026.
Impairment of oil and natural gas properties — During the nine months ended September 30, 2026, we recorded a $145.0 million impairment of our oil and natural gas properties. During the nine months ended September 30, 2025, we recorded a $284.1 million impairment of our oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” for additional information.
Price Risk Management Activities — The expense of $263.6 million for the nine months ended September 30, 2026 consists of $137.1 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $126.5 million in cash settlement losses. The income of $75.2 million for the nine months ended September 30, 2025 consists of $55.1 million in cash settlement gains and $20.1 million in non-cash gains from the increase in the fair value of our open derivative contracts.
Equity Method Investment (Income) Expense — During the nine months ended September 30, 2026, we recorded equity income of $6.5 million, which includes a $6.8 million gain on the sale of an additional 30.1% equity interest in Talos Energy Mexico 7, S. de R.L. de C.V. (“TEM 7” and the “Incremental Mexico Equity Sale”). See Part I, Item 1. “Financial Statements — Note 6 – Equity Method Investments for additional information.
Other (Income) Expense — During the nine months ended September 30, 2026, we recorded a $37.4 million loss on extinguishment of debt in conjunction with the redemption of the 9.000% 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, 2026, we recorded $26.7 million of income tax expense compared to $60.7 million of income tax benefit during the nine months ended September 30, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.
Supplemental Non-GAAP Measure
EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.
“EBITDA,” “Adjusted EBITDA” and “Adjusted EBITDA attributable to Talos Energy Inc.” 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, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc. 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) attributable to Talos Energy Inc. plus net income (loss) attributable to noncontrolling interest, plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.
•Adjusted EBITDA — EBITDA plus non-cash impairment 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 impairment of other well equipment and non-cash equity-based compensation expense.
•Adjusted EBITDA attributable to Talos Energy Inc. — Adjusted EBITDA, less adjustments for noncontrolling interest.
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, |
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
2026 |
|
2025 |
|
Net income (loss) attributable to Talos Energy Inc. |
$ |
(81,244 |
) |
$ |
(95,905 |
) |
$ |
(187,742 |
) |
$ |
(291,710 |
) |
Net income (loss) attributable to noncontrolling interest |
|
185 |
|
|
(3 |
) |
|
568 |
|
|
(3 |
) |
Net income (loss) |
|
(81,059 |
) |
|
(95,908 |
) |
|
(187,174 |
) |
|
(291,713 |
) |
Interest expense |
|
40,194 |
|
|
40,847 |
|
|
118,534 |
|
|
122,585 |
|
Income tax (benefit) expense |
|
47,111 |
|
|
(24,204 |
) |
|
26,656 |
|
|
(60,721 |
) |
Depreciation, depletion and amortization |
|
233,430 |
|
|
262,637 |
|
|
693,183 |
|
|
813,059 |
|
Accretion expense |
|
33,160 |
|
|
30,764 |
|
|
104,007 |
|
|
93,704 |
|
EBITDA |
|
272,836 |
|
|
214,136 |
|
|
755,206 |
|
|
676,914 |
|
Impairment of oil and natural gas properties |
|
— |
|
|
60,209 |
|
|
145,018 |
|
|
284,090 |
|
Transaction and other (income) expenses(1) |
|
(994 |
) |
|
9,253 |
|
|
8,955 |
|
|
3,901 |
|
Decommissioning obligations(2) |
|
(59 |
) |
|
316 |
|
|
318 |
|
|
235 |
|
Derivative fair value (gain) loss(3) |
|
120,576 |
|
|
(4,226 |
) |
|
263,574 |
|
|
(75,228 |
) |
Net cash received (paid) on settled derivative instruments(3) |
|
(29,839 |
) |
|
16,605 |
|
|
(126,455 |
) |
|
55,087 |
|
(Gain) loss on debt extinguishment |
|
37,389 |
|
|
— |
|
|
37,389 |
|
|
— |
|
Non-cash equity-based compensation expense |
|
6,379 |
|
|
4,955 |
|
|
18,124 |
|
|
13,499 |
|
Adjusted EBITDA |
|
406,288 |
|
|
301,248 |
|
|
1,102,129 |
|
|
958,498 |
|
Less: adjustment for noncontrolling interest |
|
221 |
|
|
8 |
|
|
675 |
|
|
8 |
|
Adjusted EBITDA attributable to Talos Energy Inc. |
$ |
406,067 |
|
$ |
301,240 |
|
$ |
1,101,454 |
|
$ |
958,490 |
|
(1)For the three and nine months ended September 30, 2026 and 2025, transaction expenses were not material. Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the nine months ended September 30, 2026, it includes litigation related expense of $17.3 million offset by a $6.8 million gain on the Incremental Mexico Equity Sale. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information on litigation and “Financial Statements — Note 6 — Equity Method Investments” for additional information on the Incremental Mexico Equity Sale. For the three and nine months ended September 30, 2025, it includes the derecognition of $8.9 million related to a deferred payment that was deemed uncollectible.
(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. Our primary uses of cash are for capital expenditures, acquisitions, operating costs, working capital, debt service, share repurchases, future collateral payments, and general corporate purposes. The cost of borrowing under our bank credit facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.
Effective as of the closing of the Coulomb and Na Kika Acquisition, our bank credit facility borrowing base increased from $700.0 million to $850.0 million. Our available liquidity (cash plus available capacity under the bank credit facility) was $1,076.3 million as of September 30, 2026. Letters of credit that are outstanding reduce the available bank credit commitments. The borrowing base in reserve-based lending, which is influenced by banking regulations and guidelines, is a dynamic figure subject to regular redeterminations. Changes in reserve estimations (e.g., lower production forecasts or reduced proved reserves), downward adjustments to the lender's internal price deck (i.e., commodity price expectations), and ongoing production can lead to a reduction in the borrowing base, impacting available liquidity under our bank credit facility. The next redetermination of our borrowing base is expected in the fourth quarter of 2026.
We fund drilling, completions, and development 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 additional equity issuances. We occasionally 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. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
Capital and Other Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2026 (in thousands):
|
|
|
|
U.S. drilling & completions |
$ |
250,842 |
|
Asset management(1) |
|
38,297 |
|
Seismic and G&G, land, capitalized G&A, and other |
|
70,208 |
|
Total capital expenditures |
|
359,347 |
|
Plugging & abandonment |
|
90,561 |
|
Decommissioning obligations settled(2) |
|
238 |
|
Investment in Mexico |
|
315 |
|
Total capital and other expenditures |
$ |
450,461 |
|
(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 2026 capital spending program of $475.0 million to $525.0 million and plugging & abandonment and decommissioning obligations of $135.0 million to $145.0 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.
Agreements with Collateral Requirements — We entered into arrangements (“CFSAs”) with our surety providers in the fourth quarter of 2025. The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. The collateral requirements may be secured by cash or letters of credit which will reduce our liquidity. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.
In connection with the closing of the Coulomb and Na Kika Acquisition, we entered into a decommissioning security agreement with Shell to secure the estimated decommissioning obligations associated with our interests in the acquired assets. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.
Share Repurchase Program — The Board initially approved a share repurchase program of $100.0 million on March 20, 2023, with subsequent approval of increases in share repurchase capacity of $150.0 million on July 22, 2024, approximately $42.5 million on March 25, 2025, and $157.3 million on April 27, 2026 for a total aggregate repurchase capacity of approximately $449.8 million. Approximately $176.4 million is remaining under the authorized program as of September 30, 2026. During the three and nine months ended September 30, 2026, we repurchased approximately 1.4 million and 4.1 million shares for $23.6 million and $61.8 million, respectively, excluding broker commissions. Since March 2023, in aggregate, we have repurchased 24.1 million shares for approximately $273.4 million excluding broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.
Repurchases of shares 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) each type of activity for the following periods (in thousands):
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2026 |
|
2025 |
|
Operating activities |
$ |
800,432 |
|
$ |
734,046 |
|
Investing activities |
$ |
(784,886 |
) |
$ |
(404,687 |
) |
Financing activities |
$ |
33,255 |
|
$ |
(135,382 |
) |
Operating Activities — Cash flow from operating activities increased $66.4 million in the nine months ended September 30, 2026 compared to the corresponding period in 2025. Key drivers of cash flow from operating activities are commodity prices, production volumes and operating costs as presented and discussed under the subsection entitled “— Results of Operations.”
The change between periods is primarily attributable to a $230.7 million increase in cash from earnings after non-cash items, as presented in the Condensed Consolidated Statements of Cash Flows under Part I, Item 1. “Financial Statements.” Additionally, during the nine months ended September 30, 2026, $126.5 million of cash was paid to settle expired commodity derivative instruments compared to $55.1 million of cash received for the corresponding period in 2025.
Investing Activities — Cash flow used in investing activities increased $380.2 million in the nine months ended September 30, 2026 compared to the corresponding period in 2025. During the nine months ended September 30, 2026, we made payments of $440.3 million related to acquisitions, of which $420.3 million was made in connection with the Coulomb and Na Kika Acquisition. During the nine months ended September 30, 2025, we completed the acquisition of an incremental working interest in the Monument oil discovery in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks for $14.8 million and acquired incremental working interests in U.S. Gulf of America Mississippi Canyon blocks 108 and 110 for $33.7 million. During the nine months ended September 30, 2026, we generated $53.9 million from the Incremental Mexico Equity Sale. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. Capital expenditures increased $32.7 million due to project timing between the current period and the corresponding period in 2025.
Financing Activities — Cash flow provided by (used in) financing activities increased $168.6 million in the nine months ended September 30, 2026 compared to the corresponding period in 2025. On July 13, 2026, we closed an $800.0 million notes offering (discussed below) and fully redeemed the 9.000% Notes for an aggregate payoff of $653.1 million, including a $28.1 million redemption premium. During the nine months ended September 30, 2026, we repurchased $60.8 million of our common stock through our share repurchase program compared to $103.0 million in the corresponding period in 2025. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Additionally, we incurred $24.2 million of deferred financing costs during the nine months ended September 30, 2026, of which $15.4 million related to the notes offering and $8.8 million was associated with our bank credit facility. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
Overview of Debt Instruments
8.000% Second-Priority Senior Secured Notes — due July 2034 — The $800.0 million 8.000% Second-Priority Senior Secured Notes due 2034 (the “8.000% Notes”) were issued on July 13, 2026 pursuant to a base indenture, as supplemented by a first supplemental indenture (collectively, the “2034 Indenture”), by and among the Parent Company, Talos Production Inc., as issuer of the 8.000% Notes (“Talos Production” or “Issuer”), the subsidiary guarantors party thereto (together with the Parent Company, the “8.000% Notes Guarantors”), and Wilmington Trust, National Association, as trustee and collateral agent. The 8.000% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 8.000% 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 8.000% Notes rank equally in right of payment with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the 8.000% Notes Guarantors’ future debt that is, by its term, expressly subordinated in right of payment to the 8.000% 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 8.000% Notes Guarantors (other than the Company) and any future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a junior-priority basis. The 8.000% Notes are effectively pari passu with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Second-Priority Senior Secured Notes due 2031 and are effectively junior to any existing and future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a senior-priority basis to the 8.000% Notes including indebtedness under the bank credit facility. The 8.000% Notes mature on July 15, 2034 and have interest payable semi-annually each January 15 and July 15, commencing January 15, 2027.
9.000% Second-Priority Senior Secured Notes — due February 2029 — On July 13, 2026, we redeemed the entire outstanding aggregate principal amount of the 9.000% Notes using the proceeds from the issuance of the 8.000% Notes. 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 8.000% Notes, the “Senior Notes”) were issued on February 7, 2024 pursuant to a base indenture, as supplemented by a first and second supplemental indenture (collectively, the “2031 Indenture”), by and among the Parent Company, the Issuer, the subsidiary guarantors party thereto (the “9.375% Notes Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. 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 9.375% Notes Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the 9.375% Notes 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 9.375% Notes Guarantors (other than the Company) and any future obligations of the Issuer and the 9.375% Notes 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 9.375% Notes Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 8.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the 9.375% Notes 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 additional information.
Revolving Reserve-based Credit Facility — matures January 2030 — We maintain a bank credit facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually, typically during the second quarter and fourth quarter of each year based on a proved reserves report that we deliver to the administrative agent of the bank credit facility. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional 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 discussion summarizes material changes to our contractual obligations from those disclosed in our 2025 Annual Report:
Debt — During July 2026, the $800.0 million 8.000% Notes were issued and a portion of the proceeds were used to redeem the 9.000% Notes as discussed in Part I, Item 1. “Financial Statements — Note 7 — Debt.” As a result, our long-term material cash requirements and contractual obligations disclosed in our 2025 Annual Report have been modified by extending the maturity of the refinanced indebtedness from February 2029 to July 2034. Our remaining estimated interest payments associated with our debt are now $801.8 million compared to $525.5 million disclosed in our 2025 Annual Report primarily due to the increased term of the notes and increased principal outstanding, partially offset by the lower coupon rate.
Vessel Commitments — On July 1, 2026, we entered into a 365-day minimum commitment vessel contract with a financial commitment of approximately $160.0 million. We plan to utilize the vessel for certain Deepwater drilling and completion operations commencing in mid-2027. Other joint owners, to the extent they elect to participate, will be billed for their working interest share of such costs.
Performance Obligations — As of September 30, 2026, we had outstanding performance bonds totaling $1.6 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had outstanding letters of credit issued under our bank credit facility totaling $183.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.
Critical Accounting Estimates
There have been no changes to our critical accounting estimates from those disclosed in our 2025 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
See Part I, Item 1. “Financial Statements — Note 1 — Organization, Nature of Business and Basis of Presentation.”
Recently Issued Accounting Standards
No accounting standards were issued during the quarterly period ended September 30, 2026 that were material to us. In addition, information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements — Note 1 — Organization, Nature of Business and Basis of Presentation.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2025 Annual Report. There have been no material changes from the disclosures presented in our 2025 Annual Report regarding our exposures to certain market risks.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
Our management, with the participation of 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. Based on such evaluation, our principal executive officer and principal financial officer have concluded that as of September 30, 2026, our disclosure controls and procedures were effective at a reasonable assurance level.
Our disclosure controls and procedures are designed at a reasonable assurance level 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 that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.
Internal Control over Financial Reporting
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, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
