TALOS ENERGY INC. (TALO)

CIK: 0001724965. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-25.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1724965. Latest filing source: 0001193125-26-067807.

Selected Fundamentals

Metric	Value	Unit	FY	Filed
Revenue	1,780,070,000	USD	2025	2026-02-25
Net income	-494,290,000	USD	2025	2026-02-25
Assets	5,552,057,000	USD	2025	2026-02-25

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001724965.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric	2016	2017	2018	2019	2020	2021	2022	2023	2024	2025
Revenue	258,754,000	412,828,000	891,288,000	908,064,000	575,936,000	1,244,540,000	1,651,980,000	1,457,886,000	1,973,568,000	1,780,070,000
Net income	-208,087,000	-62,868,000	221,540,000	58,729,000	-465,605,000	-182,952,000	381,915,000	187,332,000	-76,393,000	-494,290,000
Operating income	-80,679,000	45,300,000	253,129,000	213,094,000	-421,310,000	374,616,000	736,119,000	209,790,000	172,925,000	-560,280,000
Diluted EPS	-7.99	-2.01	4.81	1.08	-6.88	-2.24	4.56	1.55	-0.44	-2.82
Assets		1,239,293,000	2,479,986,000	2,589,482,000	2,834,546,000	2,766,815,000	3,058,626,000	4,816,309,000	6,191,795,000	5,552,057,000
Liabilities		1,293,380,000	1,472,490,000	1,511,205,000	1,907,945,000	2,006,162,000	1,893,050,000	2,661,158,000	3,432,090,000	3,383,934,000
Stockholders' equity	6,986,000	-54,087,000	1,007,496,000	1,078,277,000	926,601,000	760,653,000	1,165,576,000	2,155,151,000	2,759,705,000	2,167,984,000
Cash and cash equivalents		32,191,000	139,914,000	87,022,000	34,233,000	69,852,000	44,145,000	33,637,000	108,172,000	362,809,000
Net margin	-80.42%	-15.23%	24.86%	6.47%	-80.84%	-14.70%	23.12%	12.85%	-3.87%	-27.77%
Operating margin	-31.18%	10.97%	28.40%	23.47%	-73.15%	30.10%	44.56%	14.39%	8.76%	-31.48%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001724965.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarter	End Date	Revenue	Net Income	Diluted EPS	Method
2022-Q2	2022-06-30			2.33	reported discrete quarter
2022-Q3	2022-09-30			2.99	reported discrete quarter
2023-Q1	2023-03-31			0.84	reported discrete quarter
2023-Q2	2023-06-30	367,210,000	13,677,000	0.11	reported discrete quarter
2023-Q3	2023-09-30	383,135,000	-2,103,000	-0.02	reported discrete quarter
2023-Q4	2023-12-31	384,959,000	85,898,000		derived Q4 = FY annual - nine-month YTD
2024-Q1	2024-03-31	429,932,000	-112,439,000	-0.71	reported discrete quarter
2024-Q2	2024-06-30	549,165,000	12,381,000	0.07	reported discrete quarter
2024-Q3	2024-09-30	509,286,000	88,173,000	0.49	reported discrete quarter
2024-Q4	2024-12-31	485,185,000	-64,508,000		derived Q4 = FY annual - nine-month YTD
2025-Q1	2025-03-31	513,059,000	-9,868,000	-0.05	reported discrete quarter
2025-Q2	2025-06-30	424,721,000	-185,937,000	-1.05	reported discrete quarter
2025-Q3	2025-09-30	450,053,000	-95,905,000	-0.55	reported discrete quarter
2025-Q4	2025-12-31	392,237,000	-202,580,000		derived Q4 = FY annual - nine-month YTD
2026-Q1	2026-03-31	472,310,000	-256,165,000	-1.52	reported discrete quarter

Quarterly Charts

Macro Cross-References

CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
UNRATE - Unemployment Rate
FEDFUNDS - Federal Funds Effective Rate
CES0500000003 - Average Hourly Earnings of All Employees, Total Private
DFEDTARU - Federal Funds Target Range - Upper Limit
DFEDTARL - Federal Funds Target Range - Lower Limit
DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
PCEPI - Personal Consumption Expenditures: Chain-type Price Index
PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
PPIACO - Producer Price Index by Commodity: All Commodities
T10YIE - 10-Year Breakeven Inflation Rate
U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
PAYEMS - All Employees, Total Nonfarm
CIVPART - Labor Force Participation Rate
EMRATIO - Employment-Population Ratio
UNEMPLOY - Unemployed
CE16OV - Employment Level
ICSA - Initial Claims
JTSJOL - Job Openings: Total Nonfarm
JTSQUR - Quits: Total Nonfarm
GDPC1 - Real Gross Domestic Product
A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
INDPRO - Industrial Production: Total Index
TCU - Capacity Utilization: Total Index
HOUST - New Privately-Owned Housing Units Started: Total Units
PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
RSAFS - Advance Retail Sales: Retail Trade
PCE - Personal Consumption Expenditures
DSPIC96 - Real Disposable Personal Income
PSAVERT - Personal Saving Rate
M2SL - M2
BOPGSTB - U.S. International Trade in Goods and Services: Balance
MSPUS - Median Sales Price of Houses Sold for the United States
HSN1F - New One Family Houses Sold: United States
RHORUSQ156N - Homeownership Rate in the United States
TTLCONS - Total Construction Spending: Total Construction in the United States
RRVRUSQ156N - Rental Vacancy Rate in the United States
TOTALSL - Total Consumer Credit Owned and Securitized
REVOLSL - Revolving Consumer Credit Owned and Securitized
DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
GDP - Gross Domestic Product
GPDI - Gross Private Domestic Investment
GCE - Government Consumption Expenditures and Gross Investment
PCEC - Personal Consumption Expenditures
NETEXP - Net Exports of Goods and Services
GFDEBTN - Federal Debt: Total Public Debt
GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
FYFSD - Federal Surplus or Deficit
FGRECPT - Federal Government Current Receipts
FGEXPND - Federal Government: Current Expenditures
MANEMP - All Employees, Manufacturing
USCONS - All Employees, Construction
USTRADE - All Employees, Retail Trade
USFIRE - All Employees, Financial Activities
USGOVT - All Employees, Government
AWHAETP - Average Weekly Hours of All Employees, Total Private
DGORDER - Manufacturers' New Orders: Durable Goods
NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
BUSINV - Total Business Inventories
EXPGS - Exports of Goods and Services
IMPGS - Imports of Goods and Services
IR - Import Price Index (End Use): All Commodities
PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001193125-26-207039.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

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.

Table of Contents

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

•
Deepwater Operations

•
Oil Spill Response Plan

•
Hurricanes, Tropical Storms, Winter Storms and Loop Currents

•
Future Offshore Leasing

•
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.

Table of Contents

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.

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-25. Report date: 2025-12-31.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements.

This section of this Annual Report generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 27, 2025.

Our Business

We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our Upstream business in the 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.

Outlook

In 2026, we anticipate continued commodity price uncertainty, evolving global macroeconomic conditions, regulatory pressures, and shifting external expectations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Fluctuating commodity prices will directly affect our revenues.

We intend to prioritize high-margin oil production in 2026 underpinned by balanced investment in infrastructure-led development, exploration and appraisal, and multi-well development as part of the Monument Project. Capital expenditures guidance for 2026 is expected to range from $500 to $550 million. Abandonment and decommissioning expenditures are expected to range from $100 to $130 million. Non-operated capital expenditures are expected to be 40% of capital expenditures, which is an increase year over year and largely driven by the Monument Project. Approximately 10% of capital expenditures will be allocated to exploration. Production for 2026 is expected to be in the range of 62 to 66 MBopd; 85 to 90 MBoepd.

Tropical Storm Risk’s extended outlook for the 2026 Atlantic hurricane season indicates activity in line with long‑term averages—14 named storms, 7 hurricanes, and 4 major hurricanes. We incorporate expected weather‑related downtime into our operational and financial planning to maintain flexibility and support achievement of production objectives.

Operational Update

CPN — During the first quarter of 2026, we successfully drilled the CPN well with first production expected in the second half of 2026. The CPN well will tie back to our non-operated Na Kika facility. Talos is the operator of CPN and holds a 65% working interest.

Katmai — The Katmai #2 well came online in the second quarter of 2025. The Katmai Field ties back to our operated Tarantula facility. In connection with the Katmai #2 well coming online, the Tarantula gross processing capacity was expanded to 35 MBoepd to accommodate higher volumes. During the fourth quarter of 2025, gross processing capacity at the Tarantula facility was increased to approximately 38 MBoepd. Talos is the operator of the Katmai Field and holds a 50% working interest.

Genovesa — During the fourth quarter of 2025, we temporarily shut-in production from the Genovesa well, which ties back to the non-operated Na Kika facility, due to a failure of the surface-controlled subsurface safety valve resulting in deferred production of approximately 3 MBoepd. We expect the Genovesa well to return to production in the third quarter of 2026 following completion of a planned workover. Talos is the operator of Genovesa and holds a 65% working interest.

Cardona — We successfully drilled and completed the Cardona well in late 2025. Production from the Cardona well ties back to our Pompano facility. Talos is the operator and holds a 65% working interest.

Manta Ray — During the fourth quarter of 2025, we participated in the drilling of the non-operated Manta Ray well. While the well encountered hydrocarbons, it was deemed non-commercial. Talos held a 40% working interest.

Table of Contents

Daenerys — In August 2025, we announced successful drilling results at the Daenerys exploration prospect located on Walker Ridge blocks 106, 107, 150 and 151. The discovery well has been temporarily suspended to preserve its future utility. We plan to spud an appraisal well during the second quarter of 2026 to further define the discovered resource. Talos is the operator of Daenerys and holds a 27% working interest.

Recent Developments

The following encompasses recent developments since the filing of our Annual Report on Form 10-K for year ended December 31, 2024:

Amended and Restated Credit Agreement — On January 20, 2026, we entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) with a syndicate of financial institutions as lenders and JPMorgan Chase Bank, N.A. as administrative agent. The initial borrowing base and the total commitments are each $700 million. The A&R Credit Agreement replaces the Company’s amended credit agreement dated May 10, 2018. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

Lease Sale — The Big Beautiful Gulf 1 lease sale was held by BOEM on December 10, 2025. It was the first offshore oil and gas lease sale conducted under the new OBBBA. We emerged as the apparent high bidder on eleven of the twelve lease blocks on which we bid. As of February 17, 2026, we have been awarded eight of the lease blocks for which we were the high bidder and are awaiting BOEM’s award decisions on our remaining high bids.

Surety Arrangements and Collateral Requirements — In early November 2025, we entered into various collateral funding and security arrangements (“CFSAs”) to establish limits on the amount of aggregate collateral that our surety providers can require us to post. In exchange for our agreement to post the required amounts of collateral through July 1, 2031 and spend at least a specified amount on annual plugging and abandonment activities each year through 2030, the surety providers agreed not to (1) require additional collateral in excess of the agreed and scheduled amounts on existing surety bonds; (2) draw on collateral posted for the benefit of the sureties except under limited circumstances; (3) seek remedies for breaches of any surety agreement that are not an “Event of Default” as defined in the primary CFSA; or (4) cancel, or attempt to cancel, existing bonds unless requested by us.

For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, we are required to spend $90.0 million and $45.0 million on plugging and abandonment activities on an annual basis, respectively. As of December 31, 2025, our aggregate estimated collateral funding commitments under the CFSAs were $251.7 million through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies— Performance Obligations” for the estimated collateral funding commitments by year under the CFSAs. Also, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Market Outlook.”

The CFSAs generally contain certain events of default which, if triggered and not cured by us within the cure period, would terminate the standstill period and provide the sureties their full rights under their respective surety and indemnity agreements, including the right to call collateral. Events of default include, but are not limited to, the failure to maintain liquidity of $200.0 million or above a specified credit rating. However, if an event of default were to occur, it is anticipated we would be in a similar position than if we had not entered into the CFSAs given that the surety providers already have the right to demand collateral under existing surety bonds.

The CFSAs provide a multi-year framework to efficiently address the Company’s collateral commitments and abandonment activities, while strengthening the relationship with our surety providers and supporting our long-term operational strategy.

Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. Prior to this acquisition, we owned an interest in and operated these developed and producing blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Enhanced Corporate Strategy — On June 17, 2025, we announced an enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The strategy is built on three key pillars. The first pillar targets increased annualized free cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements. The second pillar focuses on growth through high-margin organic projects and selective Deepwater acquisitions. The third pillar aims to build a long-lived and scaled portfolio in the U.S. Gulf of America and potentially other conventional basins. This strategy is underpinned by a disciplined capital allocation framework which prioritizes investing in projects expected to generate robust returns through commodity cycles, returning cash to shareholders, maintaining a strong balance sheet, and growing through selective opportunities.

Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board of Directors (the “Board”) that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer was appointed by the Board. On August 12, 2025,

Table of Contents

the Board appointed Mr. Zachary B. Dailey to serve as the Company’s Executive Vice President and Chief Financial Officer and principal financial officer, effective August 18, 2025.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Appointment of President and Chief Executive Officer — Effective March 1, 2025, Mr. Paul Goodfellow was appointed President and Chief Executive Officer, principal executive officer and as an executive member of the Board.

Share Repurchase Program — During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board, resulting in $80.9 million available under the share repurchase program. See “Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information.

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

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

QuarterNorth Acquisition — On March 4, 2024, we completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

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

During the year ended December 31, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.2 MBoepd for the year ended December 31, 2024 based on production rates prior to the shut in. The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile and have remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, oil, natural gas and NGL prices have been, and may continue to be, subject to wide fluctuations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices, and sustained lower prices could adversely affect our financial results. We use hedging instruments to reduce the impact of near-term price volatility. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2025.

Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and may not adjust downward as fast as oil prices do. Inflation may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

Table of Contents

In 2025, the Federal Reserve cut interest rates three times, most recently in December, bringing the federal funds rate down to a target range of 3.50%–3.75%. These cuts mark the lowest rates since 2022. Future changes to the benchmark interest rate remain uncertain.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2025, our ceiling test calculations resulted in an impairment of our oil and natural gas properties of $454.5 million. During 2024 and 2023 our ceiling test computations for our U.S. oil and gas properties did not result in an impairment. At December 31, 2025, the Company’s ceiling test computation was based on SEC pricing of $65.37 per Bbl of oil, $3.61 per Mcf of natural gas and $19.22 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $58.76 per Bbl of oil, $3.26 per Mcf of natural gas and $17.35 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. 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 Requirements — On April 15, 2024, BOEM issued a final rule related to supplemental financial assurance requirements in the OCS entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” This rule significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “Western Louisiana District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The Western Louisiana District Court granted a stay of the litigation while BOEM pursues efforts to suspend, revise, or rescind the final rule. The Western Louisiana District Court’s order temporarily limits full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.

On May 2, 2025, the DOI announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s former policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required, and if so, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.

Notwithstanding the status of the final rule or a new revised rule, BOEM stated it will continue to require lessees on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of their decommissioning liabilities.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

Financial Assurance Market Outlook — As a result of adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of surety companies have left the offshore surety market, which has materially reduced the availability of surety bonds for projects in the OCS and may reduce the ability of companies operating in the OCS to obtain bonding without posting collateral. As a result, there may not be sufficient surety bond capacity available for companies in the OCS to comply with BOEM’s financial assurance requirements or otherwise if the final rule is not suspended, revised or rescinded or if it is not overturned pursuant to the ongoing litigation. In addition to BOEM’s financial assurance requirements, companies with whom we partner or from whom we wish to acquire assets may require that we provide financial assurance, such as surety bonds, to provide assurance that our decommissioning obligations associated with those jointly held or acquired assets can be met in the future. The tightened capacity in the surety market may impact our ability to secure surety bonds at commercially reasonable terms and therefore, our ability to enter into such joint participation or asset acquisition opportunities may be impacted.

Table of Contents

In early November 2025, we entered into CFSAs to establish limits on the amount of aggregate collateral that our surety providers can require us to post through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information.

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

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

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

Future Offshore Leasing — Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“Withdrawal Memoranda”) under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.

On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s Withdrawal Memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts. On October 2, 2025, the Western District Court of Louisiana found in part for the plaintiffs challenging the Withdrawal Memoranda, which included the States of Louisiana, Alaska, Georgia and Mississippi, the Gulf Energy Alliance and the American Petroleum Institute, and ruled that the Withdrawal Memoranda are unlawful because they exceed the authority granted to the President under OCSLA. The challenge to President Trump’s revocation of the Withdrawal Memoranda remains ongoing.

Earlier in 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. In June 2025, the comment period closed regarding BOEM’s notice requesting information and comments on the preparation of the 11th National OCS Program. On November 24, 2025, BOEM announced the availability of a draft proposed program (“DPP”) for OCS oil and gas leasing for the 2026-2031 period. The 2026-2031 DPP proposes a schedule of 34 OCS oil and gas lease sales during this five-year period, which includes 7 lease sales in the Gulf of America. These would be in addition to offshore oil and gas lease sales mandated by law outside the five-year program. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.

The OBBBA, signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%. On August 19, 2025, the DOI announced the schedule for the 30 OBBBA-mandated Gulf of America lease sales, the first of which, named the Big Beautiful Gulf 1 Lease Sale was held on December 10, 2025. This lease sale took the place of the previously announced Lease Sale 262, which had been deferred by BOEM. The remaining lease sales are expected to be held each March and August for the years 2026 through 2039, with the last of these mandated Gulf of America lease sales expected in March 2040. On February 4, 2026, BOEM announced its Final Notice of Sale for the Big Beautiful Gulf 2 Lease Sale, which is scheduled to be held on March 11, 2026.

Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations.

Table of Contents

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 NMFS, related to oil and gas activities in the Gulf of America. The vacatur was initially effective December 20, 2024, but was later extended to May 21, 2025. On May 20, 2025, NMFS published its new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. On the same day, 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 API and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. Both lawsuits seek declaratory and injunctive relief. On January 23, 2026, the Western Louisiana District Court judge issued a summary judgment in favor of the State of Louisiana, API and Chevron U.S.A. Inc., and found the 2025 Biological Opinion unlawful. The 2025 Biological Opinion was remanded, without vacatur, to NMFS to correct the Biological Opinion’s deficiencies. The 2025 Biological Opinion will remain active to avoid disruptive consequences to regulated parties. The outcome of the environmental groups’ challenge in the Maryland District Court remains uncertain at this time.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component:

Year Ended December 31,

2025

2024

2023

Oil

Natural gas

NGL

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of America basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

Table of Contents

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.

Year Ended December 31,

2025

2024

2023

Oil:

NYMEX WTI high per Bbl

75.74

85.35

89.43

NYMEX WTI low per Bbl

57.97

69.95

70.25

Average NYMEX WTI per Bbl

65.45

76.54

77.63

Average oil sales price per Bbl (including commodity derivatives)

68.18

75.07

73.59

Average oil sales price per Bbl (excluding commodity derivatives)

64.84

75.01

75.17

Natural Gas:

NYMEX Henry Hub high per MMBtu

4.26

3.18

3.27

NYMEX Henry Hub low per MMBtu

2.91

1.49

2.14

Average NYMEX Henry Hub per MMBtu

3.53

2.19

2.54

Average natural gas sales price per Mcf (including commodity derivatives)

3.70

2.65

3.32

Average natural gas sales price per Mcf (excluding commodity derivatives)

3.67

2.57

2.60

NGLs:

NGL realized price as a % of average NYMEX WTI

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our A&R Credit Agreement and Hedging Policy and may be different from what we have done on a historical basis.

Expenses

Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain reimbursements for costs from certain third parties.

Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to plug, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

Table of Contents

General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.

Interest Expense — We may finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our bank credit facility and term-based debt. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Results of Operations

Revenues

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):

Year Ended December 31,

2025

2024

Change

Revenues:

Oil

1,560,401

1,806,148

(245,747

)

Natural gas

169,445

105,528

63,917

NGL

50,224

61,892

(11,668

)

Total revenues

1,780,070

1,973,568

(193,498

)

Production Volumes:

Oil (MBbls)

24,065

24,078

(13

)

Natural gas (MMcf)

46,122

41,078

5,044

NGL (MBbls)

2,782

2,969

(187

)

Total production volume (MBoe)

34,534

33,893

641

Daily Production Volumes by Product:

Oil (MBblpd)

65.9

65.8

0.1

Natural gas (MMcfpd)

126.4

112.2

14.2

NGL (MBblpd)

7.6

8.1

(0.5

)

Total production volume (MBoepd)

94.6

92.6

2.0

Average Sale Price per Unit:

Oil (per Bbl)

64.84

75.01

(10.17

)

Natural gas (per Mcf)

3.67

2.57

1.10

NGL (per Bbl)

18.05

20.85

(2.80

)

Price per Boe

51.55

58.23

(6.68

)

Price per Boe (including realized commodity derivatives)

53.90

58.37

(4.47

)

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

Price

Volume

Total

Revenues:

Oil

(244,772

)

(975

)

(245,747

)

Natural gas

50,954

12,963

63,917

NGL

(7,769

)

(3,899

)

(11,668

)

Total revenues

(201,587

)

8,089

(193,498

)

Table of Contents

Volumetric Analysis — Production volumes increased by 2.0 MBoepd to 94.6 MBoepd for the year ended December 31, 2025. The increase was primarily due to 6.4 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there were increases of 2.3 MBoepd and 1.2 MBoepd of production from our Katmai West #2 and Sunspear wells, respectively, both of which commenced initial production in June 2025. Production volumes also increased 2.0 MBoepd due to the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by 10.6 MBoepd related to natural decline of the production rate of existing oil and natural gas wells. The absence of weather-related downtime during the 2025 hurricane season compared to the same period in 2024 was favorable to our production volumes.

Operating Expenses

Lease Operating Expense

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

Year Ended December 31,

2025

2024

Lease operating expenses

546,716

566,041

Lease operating expenses per Boe

15.83

16.70

Total lease operating expenses for the year ended December 31, 2025 decreased by approximately $19.3 million, or 3%. The decrease is primarily related to a $40.2 million decrease in facility and workover expenses primarily related to the HP-1 dry dock and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $16.9 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter 2024.

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):

Year Ended December 31,

2025

2024

Depreciation, depletion and amortization

1,056,281

1,023,558

Depreciation, depletion and amortization expense for the year ended December 31, 2025 increased by approximately $32.7 million, or 3%. This increase was primarily driven by increased production volumes of 2.0 MBoepd discussed above.

General and Administrative Expense

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

Year Ended December 31,

2025

2024

Upstream Segment

155,368

191,063

CCS Segment

—

10,454

Total general and administrative expense

155,368

201,517

Upstream general and administrative expense per Boe

4.50

5.64

General and administrative expense for the year ended December 31, 2025, decreased by approximately $46.1 million, or 23%. This decrease was primarily driven by Upstream Segment transactions costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $46.6 million or $2.65 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. This decrease was partially offset by an increase in non-cash equity-based compensation of $4.0 million compared to the same period in 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Share Based Compensation for additional information.

Table of Contents

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):

Year Ended December 31,

2025

2024

Accretion expense

125,296

117,604

Impairment of oil and natural gas properties

454,482

—

Other operating (income) expense

1,789

(109,454

)

Interest expense

163,381

187,638

Price risk management activities (income) expense

(105,455

)

1,458

Equity method investment (income) expense

1,807

10,289

Other (income) expense

(15,520

)

44,930

Income tax (benefit) expense

(109,169

)

5,003

Accretion Expense — During the year ended December 31, 2025, we recorded $125.3 million of accretion expense compared to $117.6 million during the year ended December 31, 2024. The change is primarily the result of a $4.4 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition combined with a higher asset retirement obligation subject to accretion expense. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Impairment of oil and natural gas properties — During the year ended December 31, 2025, we recorded a $454.5 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment.

Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Interest Expense — During the year ended December 31, 2025, we recorded $163.4 million of interest expense compared to $187.6 million during the year ended December 31, 2024. The change is primarily due to a $19.2 million decrease in interest expense related to the Bank Credit Facility as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Price Risk Management Activities — The income of $105.5 million for the year ended December 31, 2025 consisted of $81.5 million in cash settlement gains and $24.0 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains.

These unrealized gains and 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 Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2026, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.

Equity Method Investment (Income) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million, of which $8.0 million related to our CCS Segment that was divested in March 2024.

Other (Income) Expense — During the year ended December 31, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

Table of Contents

Income Tax Benefit (Expense) — During the year ended December 31, 2025, we recorded $109.2 million of income tax benefit compared to $5.0 million of income tax expense during the year ended December 31, 2024. The benefit of $109.2 million for the year ended December 31, 2025 is primarily due to current year activity offset with income tax expense of $28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets. For the year ended December 31, 2024, we recorded $5.0 million of income tax expense primarily related to state income tax expense of $17.7 million and an income tax benefit of $10.1 million related to current year activity inclusive of nontaxable or nondeductible items. See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Income Taxes.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings 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.

Table of Contents

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):

Year Ended December 31,

2025

2024

2023

Net income (loss) attributable to Talos Energy Inc.

(494,290

)

(76,393

)

187,332

Net income (loss) attributable to noncontrolling interest

(1,034

)

—

Net income (loss)

(495,324

)

(76,393

)

187,332

Interest expense

163,381

187,638

173,145

Income tax (benefit) expense

(109,169

)

5,003

(60,597

)

Depreciation, depletion and amortization

1,056,281

1,023,558

663,534

Accretion expense

125,296

117,604

86,152

EBITDA

740,465

1,257,410

1,049,566

Impairment of oil and natural gas properties

454,482

—

Transaction and other (income) expense(1)

5,001

(59,022

)

(33,295

)

Decommissioning obligations(2)

3,245

8,559

11,879

Derivative fair value (gain) loss(3)

(105,455

)

1,458

(80,928

)

Net cash received (paid) on settled derivative instruments(3)

81,471

4,710

(9,457

)

(Gain) loss on debt extinguishment

—

60,256

—

Non-cash equity-based compensation expense

18,418

14,462

12,953

Adjusted EBITDA

1,197,627

1,287,833

950,718

(1)
For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation. Transaction expenses include $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture related to a 49.9% equity interest in Talos Mexico sold to Zamajal. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments.

(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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — 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 new bank credit facility currently has a borrowing base of $700.0 million. As of December 31, 2025, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $965.4 million. Letters of credit that are outstanding reduce the available revolving 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. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

Table of Contents

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.

Capital and Other Expenditures — The following is a table of our capital and other expenditures, excluding acquisitions, for the year ended December 31, 2025 (in thousands):

U.S. drilling & completions

394,264

Asset management(1)

31,991

Seismic and G&G, land, capitalized G&A and other

67,812

Total capital expenditures

494,067

Plugging & abandonment

117,847

Decommissioning obligations settled(2)

1,102

Investment in Mexico

4,559

Total capital and other expenditures

617,575

(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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on decommissioning obligations.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under our bank credit facility, provide sufficient liquidity to fund 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 or obtain future borrowings under our bank credit facility, and (ii) 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 operating and economic conditions, some 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, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/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 — The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information on estimated collateral funding commitments under the CFSAs. The collateral requirements may be secured by cash or letters of credit which will reduce our liquidity.

Common Stock Repurchase Program — Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved 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, with approximately $80.9 million remaining under the authorized program as of December 31, 2025. During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 20.0 million shares under our authorized program for a total amount of $211.6 million, exclusive of broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. Our share repurchase program is subject to the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations.

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

Year Ended December 31,

2025

2024

Operating activities

935,826

962,593

Investing activities

(546,746

)

(1,320,279

)

Financing activities

(164,522

)

436,119

Table of Contents

Operating Activities — Net cash provided by operating activities decreased $26.8 million in 2025 compared to 2024. The change between periods is primarily attributable to an $80.9 million increase in cash from earnings after non-cash items, as presented in the Consolidated Statements of Cash Flows under Part IV, Item 15. Exhibits and Financial Statement Schedules, offset by a $9.1 million increase in settlement of asset retirement obligations. There was a $98.6 million decrease in cash due to changes in working capital accounts across all categories of operating assets and liabilities. Working capital at any specific point in time is subject to many variables, including commodity prices, production volumes, and the timing of cash receipts and payments.

Investing Activities — Net cash used in investing activities decreased $773.5 million in 2025 compared to 2024. Payments for acquisitions (net of cash acquired) decreased by $886.2 million. During the year ended December 31, 2024, payment for acquisitions was $936.2 million, of which $916.0 million related to the QuarterNorth Acquisition. During the year ended December 31, 2025, payment for acquisitions was $50.0 million. Proceeds from the sale of businesses decreased by $146.7 million, all of which is attributable to the TLCS Divestiture. Additionally, contributions to equity method investees decreased by $18.4 million primarily attributable to the TLCS Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information on the QuarterNorth Acquisition and the TLCS Divestiture.

Financing Activities — Net cash provided by financing activities increased $600.6 million in 2025 compared to 2024. During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. During the year ended December 31, 2025, we repurchased $119.5 million of our common stock through our common stock repurchase program compared to $45.2 million in the corresponding period in 2024 both amounts inclusive of broker commissions. See subsection above entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Furthermore, the Bank Credit Facility had no activity during the year ended December 31, 2025 compared to net repayments of $200.0 million during the corresponding period in 2024.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2025, total debt, net of discount and deferred financing costs, was approximately $1,226.2 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2025. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Bank Credit Facility — We maintained a Bank Credit Facility with a syndicate of financial institutions. The borrowing base was 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 delivered to the administrative agent of our Bank Credit Facility. As discussed above under “— Recent Developments,” the A&R Credit Agreement replaced the Bank Credit Facility in January 2026. For additional details on our Bank Credit Facility and the A&R Credit Agreement, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 12.00% Second-Priority Senior Secured Notes—due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

9.000% Second-Priority Senior Secured Notes—due February 2029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenture. The 9.000% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. 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 mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1.

9.375% Second-Priority Senior Secured Notes—due February 2031 — The 9.375% Notes were issued pursuant to the 9.375% Notes indenture. The 9.375% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. 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 mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1.

Table of Contents

Material Cash Requirements — We are party to various contractual obligations. The following discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2025:

Debt — We have two separate principal payments of $625.0 million each, corresponding to two different series of notes maturing in February 2029 and February 2031 with fixed interest rates of 9.000% and 9.375%, respectively. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Our estimated interest payments associated with our debt is $525.5 million, of which $119.9 million is due within the next twelve months.

Vessel commitments — We have $42.9 million in vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs. These vessel commitments do not extend beyond a one-year period.

Operating lease obligations — See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information.

Finance lease — We have $67.6 million in commitments related to our lease agreement for the HP-1 floating production facility in the Phoenix Field, which is utilized in our oil and natural gas development activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information, which contemplates renewal period that we are reasonably certain to exercise.

Firm transportation commitments — We have agreements in place with pipeline carriers for future transportation of oil and gas production. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information.

Plugging and Abandonment — We have arrangements with our surety providers which require us to spend at least a specified amount on plugging and abandonment activities each year. For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029,we are required to spend $90.0 million and $45.0 million on these activities on an annual basis, respectively. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information.

Performance Obligations — As of December 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured 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 the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the carrying value of our proved oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.

Our proved oil, natural gas and NGL reserves are estimated in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

Table of Contents

Estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2025 and 2024 were fully engineered by NSAI and audited by them at December 31, 2023. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2025 would have increased by an estimated $110.8 million.

The Company’s capitalized 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. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during the year ended December 31, 2025 of $454.5 million. If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells and remove or appropriately abandon all production facilities, structures and pipelines following cessation of operations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs decommissioning costs in an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Income Taxes — Our provision for income taxes includes U.S. federal and state and non-U.S. taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

Table of Contents

The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

Recently Adopted Accounting Standards

Information on Recently Adopted Accounting Standards that impacted our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

Recently Issued Accounting Standards

Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.