Talos Energy Inc (TALO) 2023 Q4 法說會逐字稿

Good day, and welcome to the Talos Energy fourth-quarter 2023 earnings call. (Operator Instructions) Please note this event is being recorded.

I would now like to turn the conference over to Jordan Kiser, Director of Corporate Finance. Please go ahead.

Good morning, everyone, and welcome to our fourth-quarter and full-year 2023 earnings conference call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; Sergio Maiworm, Senior Vice President and Chief Financial Officer; and Robin Fielder, Executive Vice President, Low Carbon Strategy and Chief Sustainability Officer.

Before we start, I'd like to remind you that our remarks will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements. Factors that could cause these results to differ materially are set forth in yesterday's press release and on our Form 10-K for the period ending December 31, 2023, filed yesterday with the SEC.

Forward-looking statements are based on assumptions as of today, and we undertake no obligation to update these statements as a result of new information or future events. During this call, we may present GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures is included in yesterday's press release filed with the SEC and available on our website.

And now I'd like to turn the call over to Tim.

Thanks, Jordan, and thanks to everyone for joining the call. As a reminder, we're going to use our earnings deck that you can pull from our website. We're going to start that deck on page 3. On the left side, we're going to talk about recent developments, and it's been a really busy three months. To start with the solid financial and operating quarter that we're going to talk about on the next slide, lot of this was due to bringing on Venice and Lime Rock ahead of schedule and above our own rate expectations.

We had three different drilling JVs restructured in the fourth quarter. Those are all outlined in the appendix: one of those was our activity in the lease sale; a second one was an acreage and prospect swap with BP, Chevron, and Hess; the third one was a large drilling JV acreage area with Repsol.

We announced our QuarterNorth transaction that we're super excited about and we'll spend a lot of time talking about today. We exited the year with our leverage stat at 1 times and $788 million of liquidity. And then as you walk into January, we were able to do a refinancing of our high-yield notes and extending our maturities and lowering our borrowing cost. And then we're super proud of that effort.

Now what really gets interesting to me is on the right side of the page, as we start to outline our 2024 objectives. What we're talking about in QuarterNorth is owning those assets for nine months out of the year as we anticipate closing that transaction in March. But even with only owning those assets in nine months, we're talking about a 35% to 40% increase from a year-over-year basis on production. But with that, an actual lowering of our capital expenditures, that's going to allow us to generate meaningful free cash flow.

And with that free cash flow, we expect to pay down debt by approximately $400 million, and then year-end 2024 with the leverage stat at 1 time. We're still going to invest in our upstream projects, and we've got a nice mix of risk and reward that we'll talk about on the drilling calendar. Those projects are outlined in the appendix. Certainly still going to pursue accretive M&A.

But what's not in this guidance is specific capital related to our TLCS business. Now we're proud of being a first mover there, and we're proud of the portfolio we've built. I think we disclosed in earlier calls, we had a capital raise process. And what we found out is that through that process, it presented optionalities that we can really think about a full strategic alternatives process, and we're going to explore that as well. I think this really comes through of us prioritizing capital allocation around free cash flow generation in the Upstream business in 2024.

So as we turn to page 4 and before we turn our attention to 2024, let's talk about the quarter we had in the fourth quarter of 2023. In the fourth quarter, we produced 67.7 thousand barrels equivalent a day of production. That is 76% oil and 83% liquids. Total corporate adjusted EBITDA was $249 million.

But I should note the Upstream adjusted EBITDA was $260 million, leading to a net back EBITDA margin of approximately $42 of BOE. CapEx was $174 million, which is actually a little lighter than we expected, allowing us to generate $27 million of adjusted free cash flow. As I mentioned earlier, we exited the year at 1 times levered.

Now as we start to think about 2024 and because we were able to bring on Venice and Lime Rock a little earlier than expected, we exited the year on the Talos side at around 75,000 barrels equivalent a day. Now as we pull in QuarterNorth and think about what that business was doing, both those businesses, combined in January, were producing 106,000 barrels equivalent a day. And I want to anchor that, as I hand it over to Sergio later to talk about our production guidance.

So moving to page 5, let's talk about Venice and Lime Rock and why we think it's such an important reflection of our strategy. You've got an image of the facility on the left, and again, it's really one of the anchor facilities in that part of the Gulf of Mexico. But as you shift the story to the right and you look at the graph, what you see is kind of the strategy in action.

First and foremost, the dash curve represents what we underwrote in the transaction. From there, the team was able to work on asset management projects. We were able to attract some third-party volumes into the facility. But more importantly, we were looking for drilling inventory, and that drilling inventory effort manifested in our ability to pull in Venice and Lime Rock.

And the exciting part about that is what you see in the yellow on the far-right side of the graph, that is the impact of that Venice and Lime Rock production. And what we're noting and what we talked about in our release is this facility will now see the highest oil volumes and production through this facility than it's seen over the last 15 years.

Let's turn to page 6, and go through the QuarterNorth transaction. This is a slide many of you have seen on the call we did related to the transaction, and we'll start on the right side of the page. These assets should produce approximately 30,000 barrels equivalent a day in 2024, keeping in mind that we expect to close this deal in the month of March. And what we're guiding here is nine months of production.

It's 75% oil-weighted and over 95% operated. It's great fit operationally and strategically, and it's a highly accretive transaction. One of the reasons it's accretive is because we think it will lower our corporate base decline, and that's influenced by Katmai's success. We also think we can unlock $50 million of annual synergies. We think it's going to, long term, be credit accretive and credit enhancing. And we think there's a good portfolio of prospects, again anchored by Katmai, and of a lot of the assets they have in the Mississippi Canyon core area for us.

If we move to page 7, we visually see how these assets lay over. So our acreage is in blue and the QuarterNorth acreage is in gold. You can see key facilities for both sides. And so, what you see here is a culmination, again, of the strategy. We have a lot of key infrastructure, it's oil weighted. There's a lot of seismic and a lot of acreage. In fact, if you look to the right side of the page, when you put the companies together, it's over 216 million barrels of proved equivalent reserves with a total proved value of over $5 billion. In fact, just the PDP value alone at SEC prices is $4.2 billion.

As we continue to aggregate acreage, we find ourselves now being the fifth largest operator in the Gulf of Mexico and the fourth largest by acreage. We think that puts us in a great position to execute this strategy that we believe in.

So let's go to slide 8. And before I talk about the capital program for the year, I want to start to remind of the earlier comments that with nine months of owning QuarterNorth, do we expect to increase year-over-year production by 35% to 40%. And if we think about that in a similar price environment, we think about a similar increase in our revenue generation as well. But yet our CapEx for 2024, we expect to go down.

If we isolated Upstream CapEx alone, that would be lower than -- that guide, the midpoint of that guide, would be lower than we were in 2023. If we look at P&A and decommissioning guidance, that we expect to be materially lower than we were in 2023. And we hope that's aided by our recent joint venture with Helix that helps us have more cost efficiencies in our P&A capital program.

If we think about that on a reinvestment rate, what we're talking about is 45% to 50%, if we're excluding P&A in the Upstream business; 55% to 60% if we're including P&A. Again, we'll spend more time talking about the drilling program. As always, we have a robust asset management program, and we're certainly going to lean in and think about new seismic expenditures with all the new acreage we're getting through the QuarterNorth transaction.

So let's go to page 9 and dig into the capital program and look at our rig program. You've got a nice mix and range of risk and reward, some development projects, including the Lobster Waterflood. We have some exploitation ideas, including what we're doing at Helm’s Deep and what we're doing at Ewing Bank 953 on a non-operated basis. And then we have the nearest project, which has a high impact prospect that, if successful, has 100 million to 300 million barrel type of target rates.

So to dive into more details and related to guidance, I'm going to hand it over to Sergio.

Thanks, Tim. Good morning, everyone, and thank you for joining our call this morning. Turning to page 10 of the presentation, we are very pleased with the financing transactions that we executed earlier in this year.

We refinanced our old bonds and raised additional capital to close on the QuarterNorth acquisition at very attractive rates. We've moved our maturities out of 2026 and moved them all over to 2029 and 2031. That was a significant process that we went through, and we're very pleased with the results.

On the bottom right of the page, I just wanted to highlight one thing: we're very pleased with attracting and ultimately seeing a large fundamental investor grow their position into the company. That's an investor that truly believes in the strategy of the company, the strong fundamentals that we have, and the management team's ability to execute on that strategy. So we're pretty happy with that.

Overall, we feel like we have a very clean capital structure with very long-dated maturities and an attractive coupon associated with that capital structure, but that's going to serve us well going into the future.

Turning over to page 11, I want to talk a little bit about how we thought about our production guidance for 2024. There are a few moving pieces. So we decided to kind of take a more detailed approach to how we guide production this year.

As you can see here on the far-left side, on a pro forma basis, the combined business can consistently produce well above 100,000 barrels of oil equivalent per day. And on the right side, we show that January was actually in that range. And February looks like it's going to be in that range as well.

But because there's some partial little contribution of QuarterNorth and a few planned maintenance projects in 2024, we felt it was important to actually walk you through how we arrived at the ultimate guided range that we were estimating for this year.

So quickly looking at or walking through that waterfall chart. So we think the business can consistently run between 105,000 and 110,000 barrels a day, and you deduct some of that production for the part of the year that we will not have a contribution for QuarterNorth, you deduct a certain portion of what we know, we're not going to be producing because we have some maintenance projects ongoing.

And we're also accounting for some weather-related issues and some potential third-party downtimes that we don't have visibility as of now, but it may happen in there. So that leads us to an 87,000 to 93,000 barrels of oil equivalent per day in 2024.

On page 12, we're going to discuss our operational and financial guidance for 2024 in a little bit more detail. As Tim alluded to earlier on the call, our production in '24 represents a 35% to 40% growth compared to last year, where our capital expenditures represents a reduction compared to 2023. Those are key metrics that will allow us to generate a significant amount of free cash flow in 2024 and ultimately allow us to pay down debt of approximately $400 million throughout this year.

So going into a little bit of more detail, let's start with production. As we saw on the last slide, we expect production to be between 87,000 and 93,000 barrels of oil equivalent per day, which is roughly 70% to 72% oil and 80% liquids. That is a very attractive commodity mix for Talos. On the cash operating expenses of $505 million to $525 million, that includes approximately $15 million of HP-1 one-time expenses related to the dry dock that starts now in March.

The workovers that we have highlighted here, those are activities that will increase production throughout the year. So we think that this is actually a very good investment that Talos should make, and that only represents $45 million to $55 million. And although these are production-enhancing activities, they're not capitalized; they're going to be expensed this year that's why we're breaking it down this way.

On the G&A side, it's $100 million to $110 million. That includes a realization of all of the synergies that we expected from the EnVen transaction and a partial realization of the synergies that we expect from the QuarterNorth transaction, reminding everybody that the full realization of the synergies related to QuarterNorth is -- we only expect that to occur at the end of the year.

As I said before, our Upstream capital expenditures of $565 million to $595 million represents a significant reduction to what we actually spend in 2023 even on a pro forma basis in 2024.

Our P&A and decommissioning costs of $90 million to $100 million in 2024 is a reduction to what we spent in '23. And if you can remember, in '23, there were a lot of non-operated activity that we were not expecting that caught us by surprise. This year, we expect to have much more control over that spending. So feel good about this estimate this year. The interest expense of $175 million to $185 million already assumes the material debt paydown throughout the year, as we talked about earlier.

Moving over to page 13, I'll turn that back over to Tim, so he can walk you through all of the capital allocation priorities for this year.

Thanks, Sergio. And I think by now, it's pretty clear what our priorities are. I mean, our first and foremost priority is to generate a significant amount of free cash flow. And our belief is the increased scale that we achieved through the QuarterNorth transaction, which also increases our oil-weighted portfolio that we believe have high net back margins, coupled with reduced capital program, is going to achieve that goal of generating significant free cash flow.

Now what's interesting about that is we believe that most of the debt we actually utilized in the transaction gets paid back in the first nine months of owning the assets. It should also generate a very competitive free cash flow yield across the E&P space.

We're still investing in the assets, though, and we believe we've got the right mix of development and exploration in our portfolio to generate good organic value. And we're not going to change our ambition and keep our eye on the ball with respect to finding more accretive M&A deals.

So with that, I'll hand it over for questions.

(Operator Instructions) Nate Pendleton, Stifel.

Good morning and congrats on the strong quarter. Understanding that you're somewhat limited in what you can say about the process for TLCS, can you provide some context around what drove you to change the nature of that capital raise and what some potential outcomes would be?

Sure, Nate, and happy to answer that. And thanks for the question. I think it was a convergence of a couple of events. I mean, I think as we mentioned on the remarks, as we started the capital raise process -- and we've mentioned this, I think, on previous calls -- that interest level was certainly there for private capital, but really there on the strategic side, and it really opened up the optionality of what this process could look like. And so put that over on one side.

And then in the middle of this, we wrapped up this QuarterNorth transaction. And I would tell you we think we have a very accretive free cash flow generative transaction, and we talked about it on the call. The very last statement I made is one that I'm honing in on, where, really, we have an opportunity, if you think about that transaction as a 50-50 debt and equity, some ability to pay back the majority of that debt in the first nine months of owning that asset.

So as that TLCS business grows, the capital requirements are going to grow and we have to really think about how do we prioritize capital allocation. And I think we want to prioritize that on free cash flow generation within the Upstream business.

We have a process that expanded its optionality and we should probably take advantage of what that looks like. And so I think it's just, again, two different events on two different sides of the house, if you will, between the businesses. We're super excited about the portfolio we've built.

We're proud of being a first mover. We also think there's a significant amount of interest on companies to have a little lower cost of capital to withstand some of the capital requirements. So capital allocation, priority decision, and I think it's the right one, and we'll see where the process leads.

Thanks. And with the activity outlined on slide 9 and the workovers you have planned, how should we think about the projection trajectory during the year and the 2024 exit rate?

Well, I think, yeah, once we -- so a couple of things on that. I mean, I saw in one of the notes, the idea of the cash costs are going up a little bit. And certainly, when you include these workovers, it looks like it's $1.50 kind of on a BOE basis of cash costs.

I would say, as Sergio said in his remarks, these are PV-additive type of projects. They happen to be encompassed in the same proved reserves, which is why they'd land on the expense side and not the capital side, but it's a good investment and I think it's something that we wanted to line up, and we're using some of the Helix vessels to do that.

I think what we tried to do in our guidance is really lay out where we end up with respect to some downtime that we're going to do related to some planned maintenance and repairs, some weather risking. Certainly, as we exit the year, we could exit -- as we bring these assets in, we could actually probably be relatively flat to where we are today. We have some new wells that are coming online in the first half of next year.

So when you get into next year, that's where you start to think about Katmai enhancements, that's where you start to think about Sunspear coming in. So I think this is a year -- and keep in mind, we've got pretty low reinvestment rate here. And so you're talking about non-P&A reinvestment between 45%, 50%. So if we can run these assets relatively flat to where they are today, see some increase in the first half of next year with some of these new projects coming online with that level of reinvestment rate, that level of free cash flow generation, I think we're in a pretty good spot.

Absolutely. Thanks for taking my questions.

Michael Scialla, Stephens.

Hey, good morning, guys. Staying on that table you have on page 9, you're going to be going to four deepwater rigs in the second half of this year versus none in the first half. I realized a couple of those are non-op.

Tim, you talked last quarter about the rig market being pretty tight. Are you anticipating a better availability and better pricing in the second half? And just trying to get a sense of could the timing of some of these prospects move around depending on how the rig market develops?

Yeah. I love the question, Michael. I think if I said yes, I expect it to go down, I would have three CEOs call me and say, hell no, I'm not saying that. So let's just look at that slide just for a second. If you look at Katmai West, Helm's Deep, and Daenerys, that's one rig line, just so you understand which one that is. So that's one rig line.

And so the Ewing Bank is a separate non-operated opportunity, and we have an opportunity to potentially take on another rig as we think about the completions of Katmai West and the completion for Sunspear. So there's a little bit of where is the market, there's some optionality we have. We potentially could push that to the right and utilize a different rig line.

So just to make sure we're on the same page, we're not taking on four rigs, certainly operate it. We have a platform rig. We have one deepwater rig commitment, another deepwater rig option. So I think we're in a good spot there.

Look, I think the rigs are at a pretty high price relative to where we are from a commodity perspective. I think that relationship when the rig inflation was happening and we had commodity markets being fairly constructive, and they're still fairly constructive, but are they constructive enough to where rig rates are.

It's one of the reasons we haven't entered into any long-term contracts, and we're still committed to not doing that for a company our size. We've talked about that, Michael, in detail. And what I think it's important for companies in the Gulf of Mexico that are our size, even as we aspire to be a bigger company, making sure we understand how we think about obligations. And so a big two-year rig obligation doesn't make sense for us. So we're playing in different types of windows. But I think I'm happy with the windows we've created to execute the program this year.

That sounds good. You talked about Sunspear and Katmai contributing to production next year. Is there any other of these prospects that could contribute? I realize Daenerys, it looks like Helm's Deep, are probably fairly long-dated, not sure about Ewing 953. Or any of those potentially going to contribute next year?

So Helm's Deep and Ewing Bank are those classic, think about those like Venice, Lime Rock, and Sunspear: good exploitation, similar to field pays, in the area broadly, and it's going to require new subsea infrastructure. So those won't contribute next year. This Lobster Waterflood is an interesting one. So that's born out of the dump flood success that we had in the Phoenix area as we own the Lobster assets now for a year and the team really examined every pay zone.

There is a big producer in the field that's got a large wet sand right in the column that we think we can utilize to do another one of these, quote, dump flood type of waterflood projects. You don't get response from that in the first two, three months. You start to get response from that as you get into the 9-month, 12-month, 15-month marker. I think we could see increased production from the Lobster field in 2025 as well because of the project we're initiating this year.

Great. I appreciate that.

Jeff Robertson, Water Tower Research.

Thanks. Good morning, Tim. With the types of acreage trades that Talos was able to accomplish in 2023, does that tell you anything about the investment environment in the Gulf of Mexico as you look at 2024 and potentially even 2025 with the type of free cash flow you anticipate?

Well, I'll make sure I understand the question. I'll try to answer. I think I heard Jeff and I didn't -- make sure you ask it again. But I think what you see in some of these trades is a better job, I think, of the operator group in the Gulf of Mexico trying to make sure they're maximizing the value of your acreage. And there's no doubt the pace of lease sales has slowed down.

There's a lease sale in the fourth quarter; we were an active participant in that. As they slow down and as we all try to develop inventory for the outer years, you have to think more broadly about how we do more business development to make sure we're all pulling our best inventory forward. And so there's still capital that wants to work in the Gulf of Mexico, and there's even new capital that's come into the Gulf of Mexico, interesting from a drilling program perspective. How can that capital go to work and how can we make sure we're all being efficient.

So I think these three announcements we made in the fourth quarter, and I think into the first quarter, are reflective of operators trying to do a better job, really making sure they've got depth and inventory as they think about '25 through '30, if you will. And these trades will all help build that depth.

And so just a straight prospect swap, an acreage swap is pretty interesting with BP and Chevron and Hess. They're all different. The Repsol one is really focused on new seismic and new reprocessing around our Neptune facility.

And then the lease sale is that normal activity. And I think we had a map in that press release, and a lot of those leases are right by a couple of our facilities and reflective of our strategy of utilizing our infrastructure. So I think it's really about inventory enhancement and inventory development in a situation where you don't have the pace of lease sales that we used to do. We've got a huge acreage position and we've got to figure out how to monetize that the best way possible.

How does the -- maybe the promote cost or the cost of doing these types of trades or the cost of getting into prospects, has that changed much in the last year with the absence of lease sales?

No, it hasn't. Typically, it's gone down. I mean, for us, just because of the level of competition has gone down, the cost of entry on a lot of these leases has gone down. So I think it's not reflective of cost. I don't think these trades are really about kind of swapping opportunities and making sure everyone's got a depth of opportunities, and there's some urgency around that.

But there's not as large of a promote market as there was when there were simply more activity and more participants, more competition for these ideas. I think we've narrowed the basin down to a group of players that are here for the long haul that are focused on inventory development or figuring out how to try to benefit from each other's inventory more than they are trying to figure out how to benefit on a trade specifically.

Thanks. And just a question on the guidance, Sergio. The planned downtime with HP-1, is that -- I presume that's going to be mostly a second quarter of '24 impact?

That's right, Jeff. It starts in March, so there's going to be an impact in the first quarter as well, but it's mostly going to impact second quarter.

Jeff, if you're ever moseying your way down to Galveston in the second quarter and you're driving down Broadway on your way to the beach, just look left.

Thank you.

Tim Rezvan, KeyBanc Capital Markets.

Good morning, folks. Thanks for taking my questions. Tim, the $400 million debt reduction is a big number, it really sort of validates this acquisition. I was a little surprised there was no commentary on repurchases with a portion of that free cash flow. So I was curious if you could maybe reflect sort of the Board's thoughts on repurchases. I know you've been willing to do it in the past. Was shares where they are today? I thought we might see some allocation there. So just any comments would be helpful.

Yeah, look, I'll provide some comments and Sergio can provide some comments. We did those under 10b-18 and they're opportunistic at the time. I think doing something more prescriptive in that when you're really trying to prioritize free cash flow generation and debt repayment isn't probably the right move as we thought about that, both as a management and a Board level.

I think we always continue to do some opportunistic things. We had $100 million program out there, we used $52 million, but I don't want to guide that that's priority. I think our absolute priority is making sure -- when you do a transaction like this, making sure you spend those first 9 to 12 months getting that balance sheet right back to where you had it. And I think that's just the highest priority we can have right now.

And then look, we are happy with our program. Although the reinvestment rate is lower, we like reinvesting in the business, but we reserve the right to always be opportunistic. I think just from a pure prioritization standpoint, debt repayment is it.

Yeah, that makes sense. Thanks. And then as my follow-up, I noticed in the release and in the presentation, not a lot of commentary on Zama. We've heard from Pemex recently that they are pushing development to the end of 2024 or 2025. Just curious if you could give us any update on what your understanding of that time line is today?

Yeah. Look, I think, it's a project. I'm always hesitant to have it guided because that's just had so many delays. And I know it's frustrating for people following the company, and I can promise you it's frustrating for me. But I would say the project's in a better spot. This is a project that we were operating, then, obviously, Pemex was operating and we were trying to make sure we had a spot of influence within that structure. And it's not a secret that we were working hard on how to create that influence.

Now we have Grupo Carso in there helping as well, and they bring a certain level of expertise; that's an enormous industrial player in the Mexico sector. So I think this has to do with really getting the right plan in place and looking at the optionality within that plan. Some of the engineering design work is taking a little longer, but it's at a place of effort to get it right. And I'm okay with that. And I'm okay with, and I certainly am thrilled, with the partner that we brought in and Talos Mexico is a co-owner of that business is that subsidiary in Grupo Carso.

So it's delayed, but I think it's delayed for the right reasons. I think it's delayed for the benefit of the project. I don't love it, and I think we've actually got a couple of other options that we're looking at, but I think it will yield the best result.

And so again -- and look, in a year, honestly where I'm trying to generate as much free cash flow as I can and show the market that these Gulf of Mexico companies can be significant free cash flow yield players, putting -- taking a little more time to get it right is probably okay as well.

Okay. So no CapEx this year towards Zama?

There is some CapEx. Look, there is some real work happening, there some real engineering design work. There's still an outside chance this could move in a little bit into '24. But I don't think we have to guide a material amount of CapEx, and I think that's what you saw in the breakdown of our guidance.

Okay. Appreciate the color. Thank you.

Jeff Robertson, Water Tower Research.

Thanks. Tim, just a question on TLCS. Are there any regulatory hurdles that might be cleared in the next six to nine months that would impact the type of valuation that the strategic alternative process could generate?

I don't think there are. There's a couple general regulatory discussions related to any potential M&A, but I don't think we have that here. But Robin, can you think of any?

Yeah. Jeff, the main updates we provided last quarter was that we submitted permits over at our Harvest Bend project in East Louisiana, for three wells in our White Castle project that were deemed administratively complete by the EPA late last year.

Since then, the state of Louisiana has received primacy. And so they now have jurisdiction over those permits. And so they're now sitting with the state regulatory body, the Louisiana Department of Energy and Natural Resources, who is now looking at it. They've got all the applications out on their website.

And so we're pleased with that process and look forward to moving into technical review discussions with them. And so that's all been positive. And then operationally, as you know, we're drilling a couple of wells there with our Bayou Bend partners in that project.

Yeah. I mean, I think for operationally, the business is moving, really, at its fastest pace ever, I would tell you, both from a Bayou Bend perspective and the well that we're drilling there, one of the first offshore dedicated injection wells right up the coast of Jefferson County. Chevron is teeing up to drill some wells onshore. We have the permits progressing in Louisiana. We have primacy in Louisiana.

So there's a lot of positive movement, which of course, I think, led to that optionality as well. So I don't want to dismiss the fact that that business is moving at a full pace. But to answer your question, I can't think off the top my head [but orders].

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.

Yes, thanks. Look, the team's worked really hard over the last three months, and I would applaud them for their efforts and thank them for their efforts. I think hooking up two wells with a full subsea development from discovery to first oil in 13 months is a really big effort, and I'm proud of them and I'm proud of that execution; they did it safely without incident.

At the same time, our business development team is putting together JVs that are going to impact how we think about our inventory in '25 through '28 and '29. And then obviously, we're super happy with what we did in the QuarterNorth transaction and how accretive that will be for our shareholders.

So a lot of effort in the last 90 days. We might have ruined a couple of holidays, but I appreciate how hard this team works, and I want to take a moment to acknowledge them. We hope that this is going to be a year. We see a lot of impact on what these announcements have for the business, and we look forward to chatting with those with you all on future calls. So thanks for joining.

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