W&T Offshore (WTI) Q4 2025 Earnings Transcript

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DATE

Tuesday, March 17, 2026 at 10 a.m. ET

CALL PARTICIPANTS

• Chairman and Chief Executive Officer — Tracy W. Krohn
• Executive Vice President and Chief Operating Officer — William J. Williford
• Executive Vice President and Chief Financial Officer — Sameer Parasnis
• Vice President and Chief Accounting Officer — Trey Hartman

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TAKEAWAYS

• Production -- Quarterly volumes rose sequentially from 30,500 barrels of oil equivalent per day in Q1 to 36,200 in Q4, with Q4 up 2% versus Q3 and 13% over the prior-year quarter.
• Capital Expenditures -- 2025 spending totaled $55 million, below the low end of guidance, supporting 34 workovers and four recompletions without new drilling activity.
• Adjusted EBITDA -- Full-year adjusted EBITDA was $130 million.
• Liquidity and Net Debt -- Cash balance increased $31 million year over year to $141 million and net debt fell $74 million to $210 million at year-end.
• Proved Reserves and PV-10 -- Year-end reserves were 121 million barrels of oil equivalent with a PV-10 of $1.1 billion; 71% classified as proved developed producing, up from 52% at prior year-end.
• Dividend Policy -- Nine consecutive quarterly cash dividends have been paid since late 2023, with another payout announced for first quarter 2026.
• LOE (Lease Operating Expense) -- Q4 LOE was $22.40 per barrel of oil equivalent, down 4% from 2025 average; costs finished below midpoint of guidance.
• Debt and Credit Actions -- A $350 million second lien notes offering in January reduced interest costs by 100 basis points and, along with other steps, lowered total debt by $39 million.
• Asset Transactions -- Non-core asset sale yielded $12 million and an insurance settlement provided $58 million in cash.
• Major Capital Project -- Completed a $20 million pipeline facility at West Delta 73 to enhance production capability and pricing; benefits expected to materialize in 2026.
• Asset Retirement -- Plugging and abandonment costs amounted to $37 million in 2025 and are forecasted near $38 million for 2026.
• 2026 Outlook -- Guidance projects lower capital expenditures near $22 million (excluding acquisitions) and full-year production midpoint of approximately 35,000 barrels of oil equivalent per day.
• 2026 LOE Guidance -- Projected to drop versus 2025, with full-year range of $265 million to $295 million, and first quarter LOE between $63 million and $70 million.
• Regulatory Update -- Department of the Interior proposed eliminating supplemental financial assurance rules, potentially reducing industry-wide bonding by $484 million annually.
• Acquisition Strategy -- Current strategic focus is on acquiring cash-generating, low-risk producing properties meeting strict free cash flow and reserve quality criteria.

SUMMARY

Management detailed robust operational execution, highlighting sequential production gains through asset integration and targeted enhancement projects while maintaining capital discipline. They emphasized that balance sheet improvements resulted from coordinated capital markets activity, non-core divestitures, and insurance recoveries, leading to higher liquidity and reduced net debt. Strategic direction centers on low-risk acquisitions and maximizing existing asset value, with reduced spending plans and an eye toward further cost savings, as leadership signaled continued dividend payments and prudent production growth for the coming year. Regulatory reforms referenced by executives could ease insurance costs and capital requirements, shaping competitive positioning across the Gulf of Mexico landscape over the next several quarters.

• Tracy W. Krohn said, "We are predicting the midpoint of Q1 2026 production to be around 35,000 barrels of oil equivalent per day," guiding to stable production levels in the coming quarters absent acquisitions or new drilling.
• William J. Williford provided operational insight that asset stimulations and recompletions are scheduled to "help maintain our production decline in Mobile Bay," with further workover inventory in multiple fields supporting a flat or upward production profile in 2026.
• Leadership stated, "first quarter gathering, transportation, and production taxes are expected to range between $8 million and $9 million," with general and administrative cash costs for the same period projected at $15 million to $17 million.
• Tracy W. Krohn identified industry-wide capital relief from Department of the Interior proposals, stating that "insurance premium costs will be going down in the future" for the company, clarifying that this is in response to the rollback of supplemental financial assurance requirements.
• The company disclosed its reserve life ratio stands at 9.8 years, with 42% of SEC proved reserves in liquids and 58% in natural gas, supporting long-term production sustainability.

INDUSTRY GLOSSARY

• PV-10: Present value of future net pre-tax cash flows from reserves, discounted at 10%, used as a standardized measure of reserve value.
• Proved Developed Producing (PDP): Reserves expected to be recovered from existing wells with existing equipment and operating methods.
• Lease Operating Expense (LOE): Direct ongoing costs incurred to operate and maintain oil and gas wells and related equipment on a producing lease.
• Workover: Operations on an existing oil or gas well to restore, sustain, or increase its production.
• Recompletion: Completing an existing well in a new zone after its initial production zone is depleted or bypassed.
• 2P Reserves: The sum of proved and probable reserves, offering a broader measure of expected recoverable volumes than 1P (proved only).
• Reserve Life Ratio: Measure of how many years proved reserves would last at the most recent year's production rate.

Full Conference Call Transcript

Tracy W. Krohn: Thanks, Al. Good morning, everyone, and welcome to our year-end 2025 conference call. With me today are William J. Williford, our Executive Vice President and Chief Operating Officer; Sameer Parasnis, our Executive Vice President and Chief Financial Officer; and Trey Hartman, our Vice President and Chief Accounting Officer. They are all available to answer questions later during the call. So we delivered solid operations and financial results in 2025 by remaining focused on our strategic vision. Our proven strategy is simple and effective: we focus on cash flow generation, maintaining and optimizing our high-quality conventional assets, and opportunistically capitalizing on accretive opportunities to build shareholder value.

We are successfully executing our strategy and remain committed to operational performance, returning value to our stakeholders, and ensuring the safety of our employees and contractors. Our ability to deliver consistent production and EBITDA results while integrating producing property acquisitions has helped W&T Offshore, Inc. grow during our 40-plus year history.

In 2025, we accomplished many things, so here are the bullet points. One, we increased production every quarter in 2025 from 30,500 barrels of oil equivalent per day in the first quarter to 36,200 barrels of oil equivalent per day in the fourth quarter by focusing on production enhancement projects. Two, while we did not drill any new wells, we did invest $55 million in 2025 CapEx and performed 34 workovers and four recompletions.

Three, we also generated adjusted EBITDA of $130 million for full year 2025, and four, we continued to focus on enhancing our liquidity and reducing debt and at year end 2025 we grew cash by $31 million year over year to almost $141 million and reduced our net debt $74 million to $210 million, further strengthening the balance sheet. And five, we reported year-end 2025 proved reserves of 121 million barrels of oil equivalent with a PV-10 of $1.1 billion. So, obviously, those numbers have gotten better since March due to geopolitics. Six, we accomplished all of this while also returning value to our shareholders through our quarterly dividend.

We have paid nine consecutive quarterly cash dividends since initiating the dividend policy in late 2023, and announced the first quarter 2026 payment that will occur later this month.

So going into a little more detail about the positive production numbers we were able to deliver in 2025. Normally, in the first quarter of every year, we have some temporary downtime associated with the impact from cold weather and freezes. We experienced some in 2025 and again in 2026 as well. But through our focused production uplift projects and continued focus on ramping up recently acquired fields, we were able to achieve quarter-over-quarter growth and year-over-year growth. In the fourth quarter, production was up 2% over Q3 2025 and up 13% over the same quarter in 2024.

So over the years, we have consistently created value by very methodically integrating producing property acquisitions, enhancing their capabilities, and thus extracting greater value. After we close any acquisition, we take time to assess and more fully evaluate the newly acquired assets. We have a large footprint across the Gulf of America, so we look for ways to optimize operations, increase production, and utilize that large footprint where we can. That reduces cost and maximizes value. We work really hard on logistics.

The assets we acquired in 2024 added meaningful reserves at attractive prices, and they required some additional capital and expense spending to maximize the production capability in all those fields. By 2025, we had also completed all the major projects on the acquired assets, and the production and cash flow benefits from the diligent work of this team to get all those properties online and up to our operating standards are reflected in our results. Moving into 2026, we remain focused on enhancing production and minimizing decline across our asset base through low-cost, low-risk workovers or rate add. We remain focused on cost control and capturing synergies associated with those asset acquisitions.

We reduced our fourth quarter LOE to $22.40 per barrel of oil equivalent, which was 4% lower compared with 2025, and our absolute costs were below the midpoint of our guidance. Looking ahead, we are expecting our 2026 costs to be lower compared to 2025, which I will discuss later in the call.

For the full year 2025, our capital expenditures were $55 million, coming in below the low end of our capital guidance. In the fourth quarter, we finished a $20 million pipeline facility project at West Delta 73 that will help support production growth, improve operational performance, and increase our net realized pricing. We expect to see the benefit of that project in 2026. Overall, our capital expense will be back-half loaded in 2025, driven by recompletion and facility capital work to bring online and increase production in multiple fields related to the 2024 acquisition. In addition, our asset retirement settlement costs totaled $37 million for 2025 as we continue to responsibly decommission assets.

Our operational performance in 2025 allowed us to focus on improving our balance sheet. At the beginning of 2025, we had several transactions that strengthened and simplified our balance sheet, adding material cash to the bottom line and improving our credit ratings from S&P and Moody's. In January, we successfully closed the $350 million offering of new second lien notes that decreased our interest rates by 100 basis points and, together with other transactions, reduced our total debt by $39 million. We also entered into a new credit agreement for a $50 million revolving credit facility which matures in July 2028 that replaced the previous $50 million credit facility provided by Calculus Lending.

We also sold a non-core interest at Garden Banks, including about 200 barrels of oil equivalent per day, for $12 million. We received $58 million in cash for an insurance settlement related to the Mobile Bay 78-1 well. All of these actions have allowed us to enhance liquidity and improve our financial flexibility. These financial actions, coupled with strong operational performance, allowed us to increase cash by $31 million and reduce our net debt by $74 million at year end 2025. All of this was accomplished in what I consider to have been a much lower price environment for oil and gas.

So our ability to execute our strategy delivered positive results in 2025, including an improved balance sheet, enhanced liquidity, growing production, and adjusted EBITDA, all of which has positioned us for success as we move into 2026. We are well positioned to take advantage of growth opportunities like we have done in the past, focusing on accretive, low-risk acquisitions of producing properties rather than high-risk drilling in the uncertain commodity price environment. These acquisitions must meet our stringent criteria of, one, generating free cash flow; two, providing a solid base of proved reserves with upside potential; and three, providing for the ability of our operations team to reduce costs.

With our experience, strong balance sheet, and over our full-year track record of successfully integrating acquisitions, we believe we are well positioned to add to this impressive portfolio of assets.

Turning to our year-end reserve results, we have a portfolio of conventional Gulf of America assets that have established record value over time. Over the past two years, our overall year-end reserves have remained virtually flat, including the volume and PV-10. We produced 24.6 million barrels of oil equivalent of production, but we also made an accretive acquisition of several fields that helped to offset this production. Since closing the latest acquisition in January 2024, we have generated almost $285 million in adjusted EBITDA, while only spending about $167 million in capital expenditures, including acquisitions.

We believe that our strategy of acquiring and enhancing producing properties continues to add value to our shareholders as reflected in our reserve amounts and value. For year-end 2025, our SEC proved reserves were 121 million barrels of oil equivalent with a PV-10 of $1,120,000,000 in a reduced price environment. Notably, we recorded an increase to PDP PV-10 of $279 million—that is proved developed producing reserves—compared to year-end 2024, as we had reserves reclassified to proved developed producing. The reserves were classified as 71% proved developed producing, 24% proved developed non-producing, and only 5% proved undeveloped. At year-end 2024, only 52% were proved developed producing and 17% were proved undeveloped.

W&T Offshore, Inc.'s reserve life ratio at year-end 2025, based on year-end 2025 proved reserves and 2025 production, was 9.8 years, about 10 years. Approximately 42% of year-end 2025 SEC proved reserves were liquids, with 32% crude oil and 10% NGLs, and we had 58% natural gas.

Yesterday, we provided detailed guidance for first quarter and full year 2026 in our earnings release. In 2026, as I previously mentioned, we incurred unplanned downtime at several fields due to winter freezes that temporarily reduced our production volumes. We are predicting the midpoint of Q1 2026 production to be around 35,000 barrels of oil equivalent per day. We are continuing to focus on production enhancement projects throughout 2026, and we expect the full 2026 production midpoint to also be around 35,000 barrels of oil equivalent per day. This is assuming no additional acquisitions or drilling. Our ability to maintain low-decline production is a testament to our quality and our culture of operational excellence and the strength of our reserves.

With several capital projects completed in 2025, we are planning much lower capital expenditures for 2026 due to a substantial reduction in capital projects associated with pipelines, at about $22 million at the midpoint, or less than half the amount invested in 2025. This does not include acquisitions. We are also forecasting about $38 million in plugging and abandonment expenses for 2026, which is in line with the $37 million we spent in 2025. We have a reliable asset base of low-decline wells. We have focused more on acquisitions over the past several years rather than on drilling many new wells, which has kept our capital spending much lower.

Turning to costs, our guidance for 2026 LOE is projected to be lower than 2025, despite higher production in 2026. Similar to the capital projects, we spent operating expenses on recently acquired fields to bring them in line with our operational standards. Additionally, some of the capital projects that we undertook in 2025 should lead to lower expenses and higher price realizations. With that said, I believe that there are more opportunities to reduce our operating costs and find synergies to drive costs lower in the long term. Safety is paramount, and we are always working hard to reduce costs without impacting safety or deferring asset integrity work.

Our first quarter 2026 LOE is expected to be between $63 million and $70 million and full-year 2026 LOE of $265 million to $295 million, which reflects the savings I mentioned earlier. Our first quarter gathering, transportation, and production taxes are expected to range between $8 million and $9 million. First quarter cash G&A costs are expected to be between $15 million and $17 million.

As we mentioned in yesterday's earnings release, the DOI, Department of the Interior, has proposed some positive regulatory changes that would roll back obligations from the 2024 rule that would have required companies to set aside about $6.9 billion in supplemental financial assurance. About $6 billion would apply to small businesses that make up most of the operators in the Gulf. The proposed changes will better align financial assurance requirements with actual decommissioning risk and could reduce industry-wide bonding by approximately $484 million annually. These proposed revisions have been published in the Federal Register with a 60-day public comment period that is expected to end on 05/08/2026.

We welcome these changes proposed by the Trump administration that can further encourage U.S. offshore production growth and further increase America's energy independence.

Before we wrap up the call, I would like to say how proud I am of all the people who have helped make W&T Offshore, Inc. a success since we founded the company in 1983. Throughout that time, we have been an active, responsible, and profitable operator in the Gulf of America. We are staunch advocates for this offshore industry. We believe that our outstanding long-life assets will continue to provide value for our shareholders and our country for many more years. As the largest shareholder, I believe we are well positioned to continue to grow and add value as we move into 2026.

Our guidance forecasts that we can modestly grow production and reduce costs, which should lead to continued build of our cash position. This allows us to remain active in evaluating growth opportunities both organically and inorganically. We have a long track record of successfully integrating those into our portfolio, and we continue to believe the Gulf of America is a world-class basin that supports value creation. We remain focused on operational excellence and maximizing the cash flow potential of our asset base. With that, operator, we can now open the lines for questions.

Operator: We will now open for questions. Please pick up your handset before pressing the keys. Our first question comes from Derrick Whitfield with Texas Capital. Good morning, all, and great update.

Derrick Whitfield: Starting with your guide, it is clear that you are prioritizing capital discipline and preservation in the current macro environment, not overly focusing on the front part of the curve. With that said, could you speak to where you see the greatest opportunity in the market for cash-on-cash returns, and if there is a sustained price scenario where you would be more inclined to engage the drill bit?

Tracy W. Krohn: Thanks, Derrick. Sure. We still think that there will be acquisitions available, and we are confident that we will have our fair share over the next one to two years. We have maintained a record over 40 years of being able to replace and replenish those reserves. So short term and long term, we still see those as possibilities for growth. Organically, we do have prospect inventory, but we feel that our efforts are better placed in making acquisitions as opposed to trying to drill right now. All those prospects, with the exception of a couple of them, are actually held by production.

Derrick Whitfield: Great. And for my follow-up, I wanted to focus on the regulatory policy updates you referenced in your prepared remarks. As you see it today, could you speak to what it means for W&T Offshore, Inc. from an insurance cost perspective? And if there could also be potential impacts to your cost of capital as you start to reduce the financial burdens?

Tracy W. Krohn: Sure. To us, that means that the insurance premium costs will be going down in the future. We have made a lot of those payments already this year. What that means is that because of the change in the regulations with regard to financial assurance, which was a term that was—supplemental financial assurance, rather—is a term that was coined in the Obama administration and further exacerbated in the Biden administration that provided so-called financial assurance for decommissioning cost. Most of these leases have in the chain of title, and that is referenced in the actual lease that operators sign as lessees.

You are required as a lessee on any lease to be jointly and severally liable for all the decommissioning liabilities on the lease. So if Exxon owned a property or Shell or Chevron or anybody owned the property 20 years ago and had a lease interest, sold it, it lapsed, whatever, and the lease comes up having remaining decommissioning liabilities, those responsible in that queue are liable jointly and severally for all of those assets being removed from the ocean floor and decommissioning of all the wells. So the government never really needed these financial assurances. This was something that was done by this administration to be punitive. Unfortunately, it removed a few companies from the Gulf.

A few of our competitors are gone that were there before. A few producers that were contributing to the overall energy output of the United States are no longer there. Clearly, those premiums could have been used better as actual capital to get rid of some of those decommissioning issues that companies had. We feel like this is a proper and fitting action that the government has taken. We applaud them greatly.

Derrick Whitfield: Terrific. Great update, guys.

Tracy W. Krohn: Thank you, sir.

Operator: Our next question comes from Jeffrey Woolf Robertson with Water Tower Research. Please go ahead.

Jeffrey Woolf Robertson: Thank you. Good morning. Tracy, can you talk about the depth of inventory W&T Offshore, Inc. has for recompletions and workovers that help you maintain or offset natural declines?

Tracy W. Krohn: I will do better than that. I will defer that question to William J. Williford, who is our Chief Operating Officer.

William J. Williford: Hey. Good morning, Jeff. Thanks for the question. We have been spending a lot of time at our Mobile Bay asset, and that is a gas asset. We have been doing a lot of asset stimulations, and we have ongoing asset stimulations set up and approved to do in 2026. That is going to help maintain our production decline in Mobile Bay. Also, we have recompletes associated with some of our deepwater fields that are already set up and already on our reserve books, and we are just executing them based on where the production is in the current well.

With that, we have several other opportunities, both on workovers and recompletes similar to that, that allow us to not only maintain the current production decline, flatten it out, but also increase it. That is why you see an increase year over year of our production based on the 2026 guidance versus what you see in 2025.

Jeffrey Woolf Robertson: With respect to the regulatory environment that Derrick asked about, Tracy, do any of the proposed changes have an effect on what is attractive to W&T Offshore, Inc. in the acquisition market and the valuations of assets?

Tracy W. Krohn: I am sorry. I did not hear all of that question. Would you repeat it again, please?

Jeffrey Woolf Robertson: With respect to the regulatory changes that you see on the horizon, how does that affect, if any, the type of acquisitions that make sense for W&T Offshore, Inc. to look at, and potentially the valuations of properties in the Gulf?

Tracy W. Krohn: Yes. One of the things that I think you will see as a result of the change in regulatory requirements is fields will be allowed to produce longer because you will not have to have these massive cash outlays or insurance outlays from a market that has shrunk and has shrunk a great deal. You will not have these massive cash and collateral requirements required by these companies to attempt to extort money from companies for their own benefit. We are involved in a lawsuit right now with some of the surety providers on an antitrust basis. So that is one of the things that we have had to deal with as an industry.

That takes away from the capital that is available to do actual work and drill wells and make improvements to leases.

Jeffrey Woolf Robertson: Thank you. And if I could ask just one more, Tracy, when you think about the types of acquisitions that you want to look at, if you focus primarily on exploitation and development, are you able to find properties that you can acquire without paying for what the seller might think is drilling upside?

Tracy W. Krohn: Drilling upside is nebulous. Of course, that is always the highest-risk asset class, or potential asset class. You never really know what you are going to find until you put a hole in the ground to investigate it. So, no, I do not think that changes the outlook. Most people do not think about additional drilling assets as primary in the consideration, unless you have already made a discovery and you are drilling on the fringes of that discovery. I think that—you know this well—this is the largest basin by area in the U.S., and it is the second largest by producing assets.

We have been able to make a pretty good living over the last 40 years and increase values for shareholders and our contractors and everybody else. It is a lovely little food chain that exists in the Gulf of Mexico. This will help continue that trend that the Obama and Biden administrations tried to get rid of.

Operator: Thank you. The next question comes from Derrick Whitfield with Texas Capital. Please go ahead.

Derrick Whitfield: Hey, guys, thanks for allowing me to ask additional questions. Before my follow-up, I wanted to ask about the facility and production enhancements you pursued with Cox and the new marketing agreement for Mobile Bay. More specifically, could you help quantify or provide color on the uplift you expect in realizations and volumes by product?

Tracy W. Krohn: That is a pretty comprehensive question, Derrick. I am not sure I have all the answers for your questions there right now as a sum total. What we do not do in the U.S. is we do not provide for a methodology of giving value to 2P reserves. So we have to go to great lengths to explain that. In Europe, you are allowed to include 2P reserves in your reserve base. In the United States, via the SEC, we are not allowed to do that. That is the bigger difference that is hard to quantify. We do see that as value, and we have seen that year over year.

As an increase to our reserves by virtue of the type of reservoirs that we have—mainly water-drive reservoirs—that will actually provide a pressure mechanism by which Mother Nature actually helps us to drive that oil to the producing perforations. We are fortunate in this basin to have Mother Nature giving us a helping hand, so to speak.

Derrick Whitfield: And, Tracy, maybe on that point, if I am looking at slide 16 of your new presentation, the way that I am reading that is that in your 2P bookings, you effectively do not need to drill any new wells and you have the probable outcome of receiving additional recovery, thereby, again, increasing longevity of the asset base without new development capital being spent. Is that a fair prediction?

Tracy W. Krohn: That is very fair. Derrick, I get a little bit nervous about quantifying some of these results because we have had, in past administrations, that has been frowned on as an expression of 2P. But clearly, we book more cash and reserves over time as we realize that 2P part of our production stream. Traditionally, think about 1P reserves as proved producing and proved undeveloped and proved behind pipe, and then 2P is probable producing and probable behind pipe, probable undeveloped.

We get a large portion—in fact, in that presentation that you referenced, it is about $750 million—of additional cash flow without any CapEx, hence, no drilling, that comes to the wellbore in the form of cash and additional reserve bookings over time. So a very effective tool that we find in the Gulf of Mexico to add value without having to make capital expenditures.

Derrick Whitfield: Great update. Thanks for your time.

Tracy W. Krohn: Thanks. You too.

Operator: This concludes our question and answer session. I would like to turn the conference back over to Tracy W. Krohn for any closing remarks.

Tracy W. Krohn: Thank you, operator. These are really unbelievable times right now. We are involved in a war in the Middle East that clearly demonstrates the point that things that affect us that we cannot control are always geopolitical. Other than that, we have pretty good control over our destiny. Even with existing or former administrations, the oil and gas business is not going to go away, fortunately. Thinking about political challenges, our business has always been challenging as a regulatory function. I do not try to belie that truth in anything other than, yes, the regulatory bodies—generally, the people that work at these agencies—have good intentions. Some of their political masters do not, and we recognize that.

But I feel like with the current administration, some of those barriers are coming down, and rightfully so. We have been persecuted as an industry and even as individuals by certain administrations. I will leave it with that and tell you that I think we will have better news next quarter as well. Thank you very much, and we will talk to you again soon.

Operator: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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