Accounts Receivable
The following table provides the components of “Accounts receivable, net” as presented on the Condensed Consolidated Balance Sheets (in thousands):
|
|
|
|
|
|
|
|
March 31, 2026 |
|
December 31, 2025 |
|
Trade |
$ |
250,447 |
|
$ |
166,793 |
|
Joint interest |
|
73,833 |
|
|
132,527 |
|
Other |
|
17,049 |
|
|
23,738 |
|
Total accounts receivable, net |
$ |
341,329 |
|
$ |
323,058 |
|
Note 2 — Acquisitions and Divestitures
Asset Acquisitions
Acquisitions accounted for as asset acquisitions require, among other items, the cost of the acquisition to be allocated to the assets acquired and liabilities assumed based on relative fair value basis.
Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an additional 8.3% non-operated 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, substantially all of which was allocated to its proved properties. An additional aggregate $6.3 million of contingent payments will be recognized upon the achievement of certain milestones defined in the agreement. This incremental acquisition brings the Company’s total non-operated working interest in the Monument oil discovery to 29.7%.
Divestitures
During the three months ended March 31, 2026, the Company sold a portion of its equity method investment in Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”). See Note 6 – Equity Method Investments for additional information.
Note 3 — Property, Plant and Equipment
Proved Properties
Capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this ceiling test calculation each quarter utilizing SEC pricing.
The Company’s ceiling test computation resulted in an impairment of its U.S. oil and natural gas properties during the three months ended March 31, 2026 of $145.0 million. The non-cash impairment is reflected as “Impairment of oil and natural gas properties” on the Condensed Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Condensed Consolidated Balance Sheets. At March 31, 2026, the Company’s ceiling test computation was based on SEC pricing of $63.17 per Bbl of oil, $3.97 per Mcf of natural gas and $18.50 per Bbl of NGLs. No impairments were recorded during the three months ended March 31, 2025.
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, the Company may incur ceiling test impairments in future quarters.
Note 4 — Leases
The Company has operating leases principally for office space, drilling rigs and other equipment necessary to support the Company’s operations. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. Additionally, the Company has a finance lease and the right-of-use (“ROU”) asset was capitalized and included in proved properties and is being depleted as part of the full cost pool.
Revolving Reserve-based Credit Facility
The Company maintains a bank credit facility with a syndicate of financial institutions. 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 its bank credit facility.
On January 20, 2026, the Parent Company, Talos Production Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Talos Production”), and certain other direct and indirect subsidiaries of the Company and Talos Production entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), the issuing banks, the lenders party thereto, and the other persons from time to time party thereto. The A&R Credit Agreement amended and restated in its entirety the prior credit agreement, dated as of May 10, 2018 (as amended, the “Prior Credit Agreement”), by and among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the issuing banks, the lenders party thereto, and the other persons party thereto.
The A&R Credit Agreement has an initial borrowing base and total commitments of $700.0 million (with a letter of credit facility with a $250 million sublimit), subject to redetermination by the lenders at least semi-annually during the second quarter and fourth quarter of each year. The maturity date of the A&R Credit Agreement is the earlier of (i) January 20, 2030 and (ii) November 2, 2028 (the 91st day prior to the earliest stated maturity date of the 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”), (or any Permitted Refinancing Indebtedness with respect thereto)), if such notes (or such Permitted Refinancing Indebtedness) have not been refinanced, redeemed, or repaid in full on or prior to such 91st day.
Interest accrues at Talos Production’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months and six-months) calculated and published by the CME Group Inc. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York. In addition, Talos Production is obligated to pay a commitment fee on the unutilized portion of the commitments. The applicable margin and the commitment fee rate are calculated based upon the utilization levels as a percentage of unused lender commitments then in effect.
The A&R Credit Agreement includes certain conditions to borrowings, representations and warranties and events of default customary for financings of its type and size. The A&R Credit Agreement also limits the Company’s, Talos Production’s and their respective subsidiaries’ ability to, among other things, incur additional indebtedness, grant liens on any assets, pay dividends or make certain restricted payments, make certain investments, consummate certain asset sales, make certain payments on indebtedness, and merge, consolidate or engage in other fundamental changes. The A&R Credit Agreement has certain customary affirmative and negative covenants, including that Talos Production must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of no greater than to 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. Talos Production must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the A&R Credit Agreement, unutilized commitments are included in current assets in the current ratio calculation. The bank credit facility is secured by, among other things, mortgages covering at least 85.0% of the proved oil and natural gas assets of the Company and is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.
Note 8 — Asset Retirement Obligations
The asset retirement obligations included in the Condensed Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):
|
|
|
|
Asset retirement obligations at December 31, 2025 |
$ |
1,332,128 |
|
Obligations incurred |
|
6,235 |
|
Obligations settled |
|
(21,869 |
) |
Accretion expense |
|
34,939 |
|
Changes in estimate |
|
13,588 |
|
Asset retirement obligations at March 31, 2026 |
$ |
1,365,021 |
|
Less: Current portion at March 31, 2026 |
|
112,962 |
|
Long-term portion at March 31, 2026 |
$ |
1,252,059 |
|
At March 31, 2026, the Company has (1) restricted cash of $76.6 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations.
The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.
Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly, and changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. The Company’s valuation allowance primarily relates to accruals for asset retirement obligations. A net deferred tax liability of $86.1 million and $156.7 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, respectively.
Note 11 — Income (Loss) Per Share
Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs and PSUs.
The following table presents the computation of the Company’s basic and diluted income (loss) per share attributable to common stockholders (in thousands, except for the per share amounts):
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
2025 |
|
Net income (loss) attributable to Talos Energy Inc. |
$ |
(256,165 |
) |
$ |
(9,868 |
) |
|
|
|
|
|
Weighted average common shares outstanding — basic |
|
168,381 |
|
|
180,192 |
|
Dilutive effect of securities |
|
— |
|
|
— |
|
Weighted average common shares outstanding — diluted |
|
168,381 |
|
|
180,192 |
|
|
|
|
|
|
Net income (loss) per share attributable to common stockholders: |
|
|
|
|
Basic |
$ |
(1.52 |
) |
$ |
(0.05 |
) |
Diluted |
$ |
(1.52 |
) |
$ |
(0.05 |
) |
Anti-dilutive potentially issuable securities excluded from diluted common shares |
|
5,431 |
|
|
3,528 |
|
Note 12 — Related Party Transactions
Slim Family and Affiliates
Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial held approximately 24.7% of the Company’s outstanding shares of common stock as of March 31, 2026 based on SEC beneficial ownership reports filed by Control Empresarial and the Company’s total outstanding shares of common stock as of that date.
The Company has a cooperation agreement with Control Empresarial that limits additional acquisitions of the Company’s voting securities by Control Empresarial if such acquisitions would result in ownership exceeding 25.0%, subject to specified exceptions. The agreement was amended on December 8, 2025 to extend its term through December 16, 2026, subject to early termination provisions. A discussion of the agreement is included in the Notes to the Consolidated Financial Statements in the 2025 Annual Report.
The Slim Family own a majority stake in Carso. Carso, through its subsidiary, has an ownership interest in Talos Mexico. See Note 6 – Equity Method Investments for additional information on Talos Mexico. At March 31, 2026 and December 31, 2025, the Company had a $2.8 million receivable from Carso related to advisory services the Company provided in connection with the Lakach Deepwater natural gas field off Mexico’s southeastern coast near Veracruz. This amount is reflected in “Accounts receivable, net” on the Condensed Consolidated Balance Sheets for both periods.
Equity Method Investments
The Company had a $0.1 million and $0.7 million related party receivable from Talos Mexico as of March 31, 2026 and December 31, 2025, respectively. These amounts are reflected in “Accounts receivable, net” on the Condensed Consolidated Balance Sheets.
Note 13 — Commitments and Contingencies
Performance Obligations
Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, and removal of facilities in the U.S. Gulf of America.
As of March 31, 2026, the Company had outstanding performance bonds from third party sureties totaling $1.5 billion. The ongoing cost of maintaining these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of March 31, 2026, the Company had letters of credit issued under its bank credit facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments.
The Company has arrangements with its surety providers that establish limits on the aggregate amount of collateral the Company may be required to post, subject to annual collateral funding commitments. These arrangements also require the Company to incur minimum annual expenditures for plugging and abandonment activities of $90.0 million for each of the three years beginning January 1, 2026 and $45.0 million for each of the two years beginning January 1, 2029.
The table below outlines the estimated collateral funding commitments under the arrangements as of March 31, 2026 (in thousands):
|
|
|
|
Period |
Collateral Funding
Commitments |
|
Remaining 2026 |
$ |
41,660 |
|
2027 |
|
42,672 |
|
2028 |
|
43,178 |
|
2029 |
|
42,112 |
|
2030 |
|
35,222 |
|
Thereafter |
|
46,759 |
|
Total |
$ |
251,603 |
|
The collateral funding commitments may be secured by cash or letters of credit which will reduce the Company’s liquidity. Collateral funded with cash will be reflected as “Restricted cash” within the Condensed Consolidated Balance Sheets. The collateral funding commitments, and ultimately any posted cash collateral, will be reduced as plugging and abandonment activities are completed and underlying surety bonds are released.
Firm Transportation Commitments
The Company has firm transportation agreements in place with pipeline carriers for future transportation of oil and gas production wherein the Company is obligated to transport minimum monthly volumes or pay for any deficiencies. As of March 31, 2026, the future minimum transportation payments under the Company’s commitments total approximately $42.1 million for years 2026 through 2030. Our production is currently expected to exceed the minimum monthly volume in the periods provided in the agreements.
Legal Proceedings and Other Contingencies
From time to time, the Company is involved in litigation, disputes related to our business, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.
Other than as described below, during the three months ended March 31, 2026, there were no material developments to those matters discussed in the Notes to the Consolidated Financial Statements in the 2025 Annual Report:
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 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
Cardona — We successfully drilled and completed the Cardona well in late 2025. Production commenced in early 2026, with the well flowing to our Pompano facility. Talos is the operator and holds a 65% working interest.
CPN — We successfully drilled the CPN well and finished well completion operations in the first quarter of 2026, with first production from the well expected in the third quarter of 2026. Talos is the operator and holds a 65% working interest.
Monument — Drilling operations have commenced and continuous drilling and completion activities are planned throughout 2026. First production is expected between 20-30 MBoepd gross and remains on track to commence by late 2026. Monument is a large Wilcox oil discovery in Walker Ridge blocks 271, 272, 315, and 316. Monument is being developed as a subsea tie-back to the Shenandoah production facility in Walker Ridge with committed firm capacity of 20 MBblpd. Talos holds a 29.7% non-operated working interest.
Recent Developments
The following encompasses recent developments since the filing of our 2025 Annual Report:
Incremental Mexico Equity Sale — On December 16, 2024, we entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal, S.A. de C.V., a subsidiary of Grupo Carso, S.A.B. de C.V., for $49.7 million in cash consideration with an additional $33.1 million payment contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale closed on March 25, 2026. See Part I, Item 1. “Financial Statements — Note 6 — Equity Method Investments” for additional information. We will receive $83.0 million in additional payments contingent upon the Zama Field reaching first oil production, of which $49.9 million is associated with the original Talos Mexico equity sale that closed on September 27, 2023, and the remainder is associated with the Incremental Mexico Equity Sale.
Lease Sale — The Big Beautiful Gulf 1 lease sale was held by BOEM on December 10, 2025. As of April 1, 2026, we have been awarded all of the eleven lease blocks for which we were the highest bidder.
Share Repurchase Program — During the three months ended March 31, 2026, we repurchased approximately 2.7 million shares for $38.2 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors (the “Board”). On April 27, 2026, our Board authorized a $157.3 million increase to the previously approved limit of the share repurchase program, increasing the amount remaining under the authorized program to $200.0 million. 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 and results of operations for the periods presented herein. Management does not currently expect any material factors to affect the comparability of our future financial condition or results of operations.
Known Trends and Uncertainties
The following known trends and uncertainties were discussed under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Annual Report:
•Volatility in Oil, Natural Gas and NGL Prices
•Inflation of Cost of Goods, Services and Personnel
•Impairment of Oil and Natural Gas Properties
•Financial Assurance Requirements
•Financial Assurance Market Outlook
•Hurricanes, Tropical Storms, Winter Storms and Loop Currents
•Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion
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.
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 — Historically, the markets for oil and natural gas have been volatile. As such, oil, natural gas and NGL prices have been, and are expected to continue to be, subject to wide fluctuations. The ongoing military conflict in Iran, which began in February 2026, has heightened geopolitical risk in key global energy markets and contributed to increased volatility in oil and gas commodity prices. The conflict has resulted in disruptions and constraints on maritime transit, supply chains, and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a critical chokepoint for global oil and liquefied natural gas shipments. These developments have led to elevated risk premiums in energy commodity prices and greater short‑term price uncertainty, causing global crude oil prices to surpass $100 per Bbl. Sustained or escalating disruptions to global supply chains, shipping routes, or energy infrastructure could materially affect global supply‑demand balances and contribute to continued volatility or increases in commodity prices. In addition, heightened market volatility may influence customer demand, counterparty credit risk, and broader macroeconomic conditions. The duration and ultimate resolution of the conflict, as well as the extent of any further disruptions, remain uncertain. We continue to monitor geopolitical developments and their potential impact on commodity prices, offshore operations, and global energy markets, but cannot predict with assurance 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 March 31, 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 has triggered inflationary pressures in the global economy. The federal funds rate target range is currently set at 3.50% to 3.75%, where it was left unchanged at the U.S. Federal Reserve’s latest meeting. Future changes to the benchmark interest rate remain uncertain in light of geopolitical conditions and expected changes to the membership of the Federal Reserve Board of Governors.
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. As a result of our ceiling test computations, an impairment of our U.S. oil and natural gas properties was recorded during the three months ended March 31, 2026 of $145.0 million. No impairment was recorded during the three months ended March 31, 2025. At March 31, 2026 our ceiling test computation was based on SEC pricing of $63.17 per Bbl of oil, $3.97 per Mcf of natural gas and $18.50 per Bbl of NGLs. 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.). BOEM, 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 BOEM’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 BOEM’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 is 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 have sought to stay the litigation pending completion of the remand order. The court has not yet ruled on this motion. At this time, it is uncertain how NMFS will address the Western Louisiana District Court’s findings and the effect this will have on the pending lawsuits.
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 March 31, |
|
|
|
|
2026 |
|
2025 |
|
Change |
|
Revenues: |
|
|
|
|
|
|
Oil |
$ |
407,998 |
|
$ |
440,723 |
|
$ |
(32,725 |
) |
Natural gas |
|
52,903 |
|
|
52,735 |
|
|
168 |
|
NGL |
|
11,409 |
|
|
19,601 |
|
|
(8,192 |
) |
Total revenues |
$ |
472,310 |
|
$ |
513,059 |
|
$ |
(40,749 |
) |
|
|
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
Oil (MBbls) |
|
5,740 |
|
|
6,144 |
|
|
(404 |
) |
Natural gas (MMcf) |
|
9,693 |
|
|
12,214 |
|
|
(2,521 |
) |
NGL (MBbls) |
|
639 |
|
|
900 |
|
|
(261 |
) |
Total production volume (MBoe) |
|
7,994 |
|
|
9,080 |
|
|
(1,086 |
) |
|
|
|
|
|
|
|
Daily Production Volumes by Product: |
|
|
|
|
|
|
Oil (MBblpd) |
|
63.8 |
|
|
68.3 |
|
|
(4.5 |
) |
Natural gas (MMcfpd) |
|
107.7 |
|
|
135.7 |
|
|
(28.0 |
) |
NGL (MBblpd) |
|
7.1 |
|
|
10.0 |
|
|
(2.9 |
) |
Total production volume (MBoepd) |
|
88.8 |
|
|
100.9 |
|
|
(12.1 |
) |
|
|
|
|
|
|
|
Average Sale Price Per Unit: |
|
|
|
|
|
|
Oil (per Bbl) |
$ |
71.08 |
|
$ |
71.73 |
|
$ |
(0.65 |
) |
Natural gas (per Mcf) |
$ |
5.46 |
|
$ |
4.32 |
|
$ |
1.14 |
|
NGL (per Bbl) |
$ |
17.85 |
|
$ |
21.78 |
|
$ |
(3.93 |
) |
Price per Boe |
$ |
59.08 |
|
$ |
56.50 |
|
$ |
2.58 |
|
Price per Boe (including realized commodity derivatives) |
$ |
56.27 |
|
$ |
57.07 |
|
$ |
(0.80 |
) |
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 March 31, 2026 vs 2025 |
|
|
Price |
|
Volume |
|
Total |
|
Revenues: |
|
|
|
|
|
|
Oil |
$ |
(3,746 |
) |
$ |
(28,979 |
) |
$ |
(32,725 |
) |
Natural gas |
|
11,059 |
|
|
(10,891 |
) |
|
168 |
|
NGL |
|
(2,507 |
) |
|
(5,685 |
) |
|
(8,192 |
) |
Total revenues |
$ |
4,806 |
|
$ |
(45,555 |
) |
$ |
(40,749 |
) |
Three Months Ended March 31, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 12.1 MBoepd to 88.8 MBoepd. This decrease is primarily attributable to a 6.3 MBoepd decline at the Brutus field, driven by a high-rate gas recompletion, where the well has declined as expected and will be sidetracked to a deeper target in the upcoming Brutus rig program, as well as a 3.7 MBoepd decrease at the Galapagos field primarily related to a shut-in due to a failure of the surface-controlled subsurface safety valve at the Genovesa well. We expect the Genovesa well to return to production in the third quarter of 2026 following completion of a planned workover. These decreases were partially offset by increases of 3.5 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 March 31, |
|
|
2026 |
|
2025 |
|
Lease operating expenses |
$ |
129,035 |
|
$ |
127,805 |
|
Lease operating expenses per Boe |
$ |
16.14 |
|
$ |
14.08 |
|
Three Months Ended March 31, 2026 and 2025 — Lease operating expense was relatively flat for the three months ended March 31, 2026 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 March 31, |
|
|
2026 |
|
2025 |
|
Depreciation, depletion and amortization |
$ |
230,384 |
|
$ |
280,716 |
|
Three Months Ended March 31, 2026 and 2025 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended March 31, 2026 decreased by approximately $50.3 million, or 18%. This decrease was primarily driven by decreased production volumes of 12.1 MBoepd discussed above as well as a decrease of $2.10 per Boe, or 7%, in the depletion rate on our proved oil and natural gas properties. The decreased production volumes and change in DD&A rate between periods caused DD&A expense to decrease by $33.5 million and $16.9 million, respectively.
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 March 31, |
|
|
2026 |
|
2025 |
|
General and administrative expense |
$ |
40,970 |
|
$ |
34,615 |
|
General and administrative expense per Boe |
$ |
5.13 |
|
$ |
3.81 |
|
Three Months Ended March 31, 2026 and 2025 — General and administrative expense for the three months ended March 31, 2026 increased by approximately $6.4 million, or 18%, 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 March 31, |
|
|
2026 |
|
2025 |
|
Accretion expense |
$ |
34,939 |
|
$ |
30,894 |
|
Impairment of oil and natural gas properties |
$ |
145,018 |
|
$ |
— |
|
Other operating (income) expense |
$ |
11,347 |
|
$ |
(4,536 |
) |
Interest expense |
$ |
39,178 |
|
$ |
40,927 |
|
Price risk management activities (income) expense |
$ |
173,547 |
|
$ |
15,853 |
|
Equity method investment (income) expense |
$ |
(6,670 |
) |
$ |
490 |
|
Other (income) expense |
$ |
(4,185 |
) |
$ |
(3,860 |
) |
Income tax (benefit) expense |
$ |
(65,292 |
) |
$ |
(91 |
) |
Three Months Ended March 31, 2026 and 2025 —
Impairment of oil and natural gas properties — During the three months ended March 31, 2026, we recorded a $145.0 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.”
Other Operating (Income) Expense — During the three months ended March 31, 2026, we agreed to settle a lawsuit for $14.3 million. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.
Price Risk Management Activities — The expense of $173.5 million for the three months ended March 31, 2026 consists of $151.1 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $22.4 million in cash settlement losses. The expense of $15.9 million for the three months ended March 31, 2025 consists of $21.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $5.2 million in cash settlement gains.
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 June 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.”
Equity Method Investment (Income) Expense — During the three months ended March 31, 2026, we recorded equity income of $6.7 million, which includes a $6.8 million gain on the Incremental Mexico Equity Sale.
Income Tax (Benefit) Expense — During the three months ended March 31, 2026, we recorded $65.3 million of income tax benefit compared to $0.1 million of income tax benefit during the three months ended March 31, 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 March 31, |
|
|
2026 |
|
2025 |
|
Net income (loss) attributable to Talos Energy Inc. |
$ |
(256,165 |
) |
$ |
(9,868 |
) |
Net income (loss) attributable to noncontrolling interest |
|
161 |
|
|
— |
|
Net income (loss) |
|
(256,004 |
) |
|
(9,868 |
) |
Interest expense |
|
39,178 |
|
|
40,927 |
|
Income tax (benefit) expense |
|
(65,292 |
) |
|
(91 |
) |
Depreciation, depletion and amortization |
|
230,384 |
|
|
280,716 |
|
Accretion expense |
|
34,939 |
|
|
30,894 |
|
EBITDA |
|
(16,795 |
) |
|
342,578 |
|
Impairment of oil and natural gas properties |
|
145,018 |
|
|
— |
|
Transaction and other (income) expenses(1) |
|
8,605 |
|
|
(4,579 |
) |
Decommissioning obligations(2) |
|
162 |
|
|
(157 |
) |
Derivative fair value (gain) loss(3) |
|
173,547 |
|
|
15,853 |
|
Net cash received (paid) on settled derivative instruments(3) |
|
(22,470 |
) |
|
5,167 |
|
Non-cash equity-based compensation expense |
|
5,336 |
|
|
4,141 |
|
Adjusted EBITDA |
|
293,403 |
|
|
363,003 |
|
Less: adjustment for noncontrolling interest |
|
196 |
|
|
— |
|
Adjusted EBITDA attributable to Talos Energy Inc. |
$ |
293,207 |
|
$ |
363,003 |
|
(1)For the three months ended March 31, 2026, 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 three months ended March 31, 2026, it includes a $14.3 million litigation settlement accrued as an expense 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 the litigation settlement and “Financial Statements — Note 6 — Equity Method Investments” for additional information on the Incremental Mexico Equity Sale. For the three months ended March 31, 2025, neither transaction expenses nor other income (expense) were material.
(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, operating costs, working capital, debt service, share repurchases, future collateral payments and for 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.
Our bank credit facility currently has a borrowing base of $700.0 million. Our available liquidity (cash plus available capacity under the bank credit facility) was $989.0 million as of March 31, 2026. Letters of credit that are outstanding reduce the available bank credit commitments. The next redetermination of our borrowing base is expected in the second quarter of 2026. 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.
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 three months ended March 31, 2026 (in thousands):
|
|
|
|
U.S. drilling & completions |
$ |
68,925 |
|
Asset management(1) |
|
16,051 |
|
Seismic and G&G, land, capitalized G&A and other |
|
33,970 |
|
Total capital expenditures |
|
118,946 |
|
Plugging & abandonment |
|
21,869 |
|
Decommissioning obligations settled(2) |
|
59 |
|
Total capital and other expenditures |
$ |
140,874 |
|
(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 $500.0 million to $550.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $130.0 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.
Surety Agreements and Collateral Requirements — We entered into arrangements (“CFSAs”) with our surety providers toward the end 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.
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 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million. Approximately $42.7 million is remaining under the authorized program as of March 31, 2026. During the three months ended March 31, 2026, we repurchased approximately 2.7 million shares for $38.2 million excluding broker commissions. On April 27, 2026, our Board authorized an increase of $157.3 million to the previously approved limit increasing the amount remaining under the authorized program to $200.0 million. Since March 2023, in aggregate, we have repurchased 22.7 million shares for approximately $249.8 million excluding broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.
Repurchases of stock 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):
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
2025 |
|
Operating activities |
$ |
174,001 |
|
$ |
268,241 |
|
Investing activities |
$ |
(89,580 |
) |
$ |
(143,308 |
) |
Financing activities |
$ |
(60,458 |
) |
$ |
(29,394 |
) |
Operating Activities — Cash flow from operating activities decreased $94.2 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. Key drivers of cash flow from operating activities are commodity prices, production volumes and operating costs. The change between periods is largely attributable to a $40.7 million decrease in revenues due to a decrease in production volumes between periods as discussed above under the subsection entitled “— Results of Operations.” During the three months ended March 31, 2026, $22.5 million of cash was paid to settle expired commodity derivative instruments compared to $5.2 million of cash received for the corresponding period in 2025. Additionally, settlement of asset retirement obligations increased $12.1 million between the current period and the corresponding period in 2025.
Investing Activities — Cash flow used in investing activities decreased $53.7 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. This is primarily due to $49.7 million in cash consideration generated from the Incremental Mexico Equity Sale during three months ended March 31, 2026. Capital expenditures increased $23.4 million due to project timing between the current period and the corresponding period in 2025. During the three months ended March 31, 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 compared to no acquisition payments during the three months ended March 31, 2026. Additionally, proceeds from the sale of property and equipment increased $12.6 million between the current period and the corresponding period in 2025.
Financing Activities — Cash flow used in financing activities increased $31.1 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. During the three months ended March 31, 2026, we repurchased $38.2 million of our common stock through our share repurchase program compared to $17.3 million in the corresponding period in 2025. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Additionally, we incurred $6.9 million of deferred financing costs during the three months ended March 31, 2026 in connection with an amended and restated credit agreement that was executed on January 20, 2026. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
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 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 9.000% 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 additional 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 “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 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 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 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 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. There have been no material changes to our contractual obligations since those reported in our 2025 Annual Report.
Performance Obligations — As of March 31, 2026, we had outstanding performance bonds totaling $1.5 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 $97.4 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
None.
Recently Issued Accounting Standards
No accounting standards were issued during the quarterly period ended March 31, 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 March 31, 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 March 31, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
