Talos Energy Inc. Q4 FY2023 Earnings Call

Good day, and welcome to the Talos Energy Fourth Quarter 2023 Earnings Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. 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. Let's start with the solid financial and operating quarter that we're going to talk about on the next slide. A 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; and 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 debt at 1x and $788 million of liquidity. As we walk into January, we were able to refinance our high-yield notes by extending our maturities and lowering our borrowing costs. We're proud of that effort. Now what it 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. Even with only owning those assets for 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 is going to allow us to generate meaningful free cash flow. With that free cash flow, we expect to pay down debt by approximately $400 million and end year-end 2024 with leverage debt at 1x. 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, and we're certainly going to pursue accretive M&A. What’s not in this guidance is specific capital related to our TLCS business. 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 that we had a capital raise process. 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. This really comes through our prioritizing capital allocation around free cash flow generation in the upstream business in 2024. Turning to Page 4 and before we transition to 2024, let's talk about the quarter we had in the fourth quarter of 2023. In the fourth quarter, we produced 67.7 barrels equivalent per day of production, which is 76% oil and 83% liquids. Total corporate adjusted EBITDA was $249 million. The upstream adjusted EBITDA was $260 million, leading to a net back EBITDA margin of approximately $42 per BOE. CapEx was $174 million, which is a bit lighter than we expected, allowing us to generate $27 million of adjusted free cash flow. We exited the year at 1x leverage. 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 per day. 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 per day, and I want to anchor that as I hand it over to Sergio later to discuss our production guidance. 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, you see the strategy in action. First and foremost, the dashed curve represents what we underwrote in the transaction. From there, the team was able to work on asset management projects and track some third-party volumes into the facility. More importantly, we were looking for drilling inventory. That drilling inventory effort manifested in our ability to pull in Venice and Lime Rock. The exciting part about that is what you see in yellow on the far right side of the graph. That is the impact of that Venice and Lime Rock production. We're noting that this facility will now see the highest oil volumes in 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. These assets should produce approximately 30,000 barrels equivalent per day in 2024. Keeping in mind that we expect to close this deal in March and we’re guiding nine months of production. It's 75% oil-weighted and over 95% operated. It's a 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, influenced by Katmai's success. We also think we can unlock $50 million of annual synergies. It will be long-term credit accretive and enhancing, and we think there's a good portfolio of prospects, anchored by Katmai and a lot of the assets they have in the Mississippi Canyon core area for us. If we move to Page 7, we see how these assets lay over. Our acreage is in blue and QuarterNorth acreage is in gold. You can see key facilities for both sides. What you see here is a culmination of the strategy. We have a lot of key infrastructure, it's oil-weighted, and there is a lot of seismic and acreage. In fact, 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. Just the PDP value alone at SEC prices is $4.2 billion. We continue to aggregate acreage, and 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 our strategy. Let’s go to Slide 8. Before I talk about the capital program for the year, I want to remind you that with nine months of owning QuarterNorth, we expect to increase year-over-year production by 35% to 40%. In a similar price environment, we expect similar increases in our revenue generation as well. Our CapEx for 2024 is expected to go down. If we isolated upstream CapEx alone, the midpoint of that guide would be lower than we were in 2023. We expect P&A and decommissioning guidance to be materially lower than in 2023, aided by a recent joint venture with Helix that helps us achieve more cost efficiencies in our P&A capital program. Looking at our reinvestment rate, we’re talking about 45% to 50% excluding P&A in the upstream business, and 55% to 60% including P&A. Again, we will spend more time talking about the drilling program. We have a robust asset management program and we're going to lean into new seismic expenditures with all the new acreage we're getting through the QuarterNorth transaction. On Page 9, let’s dig into the capital program and look at our rig program. You have a nice mix and range of risk and reward, with development projects including the Lobster Waterflood. We have some exploitation ideas at Helm’s Deep and Ewing Bank 953 on a non-operated basis. We also have the Daenerys project, which is a high-impact prospect that, if successful, has a target range of 100 million to 300 million barrels. To dive into more details 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 we executed earlier 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 from 2026 to 2029 and 2031. That was a significant process that we went through and we are very pleased with the results. On the bottom right of the page, I just wanted to highlight one thing. We are very pleased with attracting and ultimately seeing a large fundamental investor grow their position in the company. That’s an investor that truly believes in the strategy of the company, the strong fundamentals we have, and the management team’s ability to execute that strategy. Overall, we feel like we have a very clean capital structure with long data maturities and an attractive coupon associated with that capital structure that will serve us well going into the future. Turning over to Page 11, I want to talk about how we thought about our production guidance for 2024. There are a few moving pieces so we decided to take a more detailed approach to how we guide production this year. 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. 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. However, because of some partial new contributions from QuarterNorth and a few planned maintenance projects in 2024, we felt it was important to walk you through how we arrived at the ultimate guided range we are estimating for this year. Quickly looking at that waterfall chart, we think the business can consistently run between 105,000 and 110,000 barrels a day. We deduct some of that production for the part of the year that we will not have a contribution from QuarterNorth. We also account for some weather-related issues and some potential third-party downtimes that we don’t have visibility on right now. This leads us to an estimated production range of 87,000 to 93,000 barrels of oil equivalent per day in 2024. On Page 12, we will discuss our operation and financial guidance for 2024 in more detail. Our production in 2024 represents a 35% to 40% growth compared to last year, whereas our capital expenditures will be a reduction compared to 2023. Those are key metrics that will allow us to generate a significant amount of free cash flow in 2024, allowing us to pay down debt of approximately $400 million throughout this year. Starting 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—a very attractive commodity mix for Talos. Cash operating expenses are estimated at $505 million to $525 million, which includes approximately $15 million of HP-1 onetime expenses related to the dry dock that starts now in March. The workovers we have highlighted are activities that will increase production throughout the year, representing an investment of $45 million to $55 million. Although these are production-enhancing activities, they’re not capitalized and will be expensed this year. On the G&A side, our estimate is $100 million to $110 million, including a realization of all synergies expected from the EnVen transaction and a partial realization of the synergies expected from the QuarterNorth transaction. The full realization of the synergies related to QuarterNorth is expected by the end of the year. Our upstream capital expenditures of $565 million to $595 million represent a significant reduction compared to what we actually spent in 2023, even on a pro forma basis in 2024. Our P&A and decommissioning costs of $90 million to $100 million in 2024 are also a reduction from 2023. In 2023, there were non-operated activities that we were not expecting, which caught us by surprise. This year, we expect to have much more control over that spending and feel good about this estimate. The interest expense of $175 million to $185 million already assumes the material debt paid down throughout the year as discussed earlier. Moving to Page 13, I’ll turn this back over to Tim so he can talk you through the capital allocation priorities for this year.

Thanks, Sergio. By now, it’s clear what our priorities are. Our foremost priority is to generate a significant amount of free cash flow. We believe the increased scale we achieved through the QuarterNorth transaction, which also increases our oil-weighted portfolio with high netback margins, coupled with the reduced capital program, will achieve our goal of generating significant free cash flow. Most of the debt we utilized in the transaction should be paid back in the first nine months of owning the assets, which also generates a very competitive free cash flow yield across the E&P space. We will continue investing in the assets, and we believe we have the right mix of development and exploration in our portfolio to generate good organic value. We will keep our eye on finding more accretive M&A deals. With that, I’ll hand it over for questions.

We will now begin the question-and-answer session. Our first question comes from Nate Pendleton with Stifel. Please go ahead.

Good morning. Congrats on the strong quarter. Understanding that you are 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 might be?

Yes, sure Nate. Happy to answer that and thanks for the question. It was a convergence of a couple of events. As we mentioned in the remarks, when we started the capital raise process, the interest level was certainly there for private capital but really there on the strategic side. That really opened up kind of the optionality of what this process could look like. At the same time, we wrapped up the QuarterNorth transaction. We believe it is a very accretive and free cash flow generative transaction, and we've talked about it on the call. If you think about that transaction as fifty-fifty debt and equity, some ability to pay back the majority of that debt in the first nine months, as the TLCS business grows, the capital requirement is going to grow. We have to think about how do we prioritize capital allocation. We want to prioritize that on free cash flow generation within the upstream business. As that process expanded its optionality, we should probably take advantage of what that looks like. It’s just two different events on two different sides of the house. We’re super excited about the portfolio we've built. We’re proud of being a first mover. We also think there is significant interest from companies that have a lower cost of capital, which helps with capital requirements. Managing capital allocation priority is the right decision, and we'll see where the process leads.

Got it. Thanks. With the activity outlined on Slide 9 and the workovers you have planned, how should we think about the production trajectory during the year and the 2024 exit rate?

I think, yes, once we – so a couple things on that. I saw in one of the notes, the idea of the cash costs going up a little bit. Certainly, including these workovers looks like it’s a $1.50 kind of on a BOE basis of cash costs. 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 land on the expense side and not the capital side. But it's a good investment. We want to line that up using some of the Helix vessels. You’re going to have— I think what we tried to do in our guidance is lay out where we end up with respect to some downtime related to planned maintenance and repairs, weather risks. As we exit the year, we could exit relatively flat to where we are today. We have new wells coming online in the first half of next year. That’s where you start to think about Katmai enhancements and Sunspear coming in. It’s a year where we’re trying to generate as much free cash flow as we can.

Absolutely. Thanks for taking my question.

The next question comes from Michael Scialla with Stephens. Please go ahead.

Hey, good morning, guys. Standing on that table you have on Page 9, you're going to four deepwater rigs in the second half of this year versus none in the first half. Tim, you talked last quarter about the rig market being pretty tight. Are you anticipating greater availability and better pricing in the second half? I'm trying to get a sense of whether the timing of some of these prospects could shift around depending on how the rig market develops.

Yes. I love the question, Michael. If I said yes, I expected to go down, I’ve had three CEOs call me saying, 'hell no,' so—but 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. The other deepwater rig commitment is a different opportunity. We have flexibility, which means we can push those projects to the right if the market is too tight. The rig market is at a pretty high price relative to where we are from a commodity perspective and that relationship to rig inflation is one reason we haven't entered long-term contracts. We’re committed to not doing that for a company our size. So we are 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. Are there other prospects that could contribute? I realize that Daenerys and Helm’s Deep are probably longer-term.

Helm’s Deep and Ewing Bank are those classic scenarios. Think about those like Venice, Lime Rock, and Sunspear. They require new subsea infrastructure, meaning they won't contribute next year. The Lobster Waterflood is an interesting project, stemming from our dump flood success in the Phoenix Area, where we own the Lobster assets. The team examined every pay zone—it’s a big producer in the field. We think we can initiate another one of these dump flood type of water flood projects. You won’t see immediate response from that in the first couple of months; you begin to see response as we hit about the nine to twelve months mark. We think we can see increased production from the Lobster field in 2024, 2025 as well because of the project we will initiate this year.

Great. Appreciate that. All right. Got it.

The next question comes from Jeff Robertson with Water Tower Research. Please go ahead.

Thanks. Good morning, Tim. With the acreage trades Talos was able to accomplish in 2023, does that provide insight into the investment environment in the Gulf of Mexico as you look to 2024 and 2025 with the free cash flow you anticipate?

I’ll ensure I understand your question. I think I heard, but I want to confirm. What you see in some of these trades is a better effort by the operator group in the Gulf of Mexico to maximize the value of acreage. There’s no doubt that the pace of lease sales has slowed down. There was a lease sale in the fourth quarter, and we participated actively. As the pace slows and we all try to develop inventory for the outer years, we need to think more broadly about how to do business development to ensure all our best inventory is being pulled forward. There is still capital interested in the Gulf of Mexico, even new capital, from a drilling program perspective, but we must be efficient. These three announcements we made in the fourth quarter and the first quarter are reflective of operators better managing their inventory as they look at 2025 through 2030. These trades help build that depth. An acreage swap, for example, becomes interesting with BP, Chevron, and Hess. The Repsol trade focused on new seismic work around our Neptune facility and normal lease sale activity. We need to effectively monetize our huge acreage position.

Has the promote cost or the cost of doing these types of trades changed in the last year with the decline in lease sales?

No, it hasn't typically. It’s actually gone down. For us, the level of competition has decreased, leading to a reduced cost of entry on many of these leases. These trades are about swapping opportunities to ensure there's a depth of opportunities. There's not as large of a promote market as before when there was more activity. We've narrowed the basin to players who are committed for the long haul, focusing on inventory development rather than maximizing trade benefits.

Thanks. Just a question on the guidance, Sergio. Is the planned downtime with HP-1 primarily going to impact the second quarter of 2024?

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

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

The next question comes from Tim Rezvan with KeyBanc Capital Markets. Please go ahead.

Hey. Good morning folks. Thanks for taking my question. Tim, the $400 million debt reduction is a big number. It validates this acquisition. I was surprised there was no commentary on repurchases with a portion of that free cash flow. Any reflections on the Board's thoughts regarding repurchases? I know you've been willing to do this in the past. With shares where they are today, I thought we might see some allocation there, so any comments would be helpful.

Yes. Look, I'll provide some comments, and Sergio can follow. We did this under a 10b-18 and were opportunistic. We don’t think a prescriptive approach makes sense right now with our focus on free cash flow generation and debt repayment. We can continue to engage in opportunistic activities. We had a $100 million program, having used $52 million, but I don't want to guide on that. The priority now is ensuring we put the balance sheet back in order after this transaction. We are happy with our program. Although the reinvestment rate is lower, we like putting capital back into the business. However, prioritization is on debt reduction.

That makes sense. Thanks. As a follow-up, I noticed in the release and presentation that there wasn’t much commentary on Zama. Recently we heard from Pemex that development is being pushed to the end of 2024 or into 2025. What’s your understanding of that timeline?

Yes. Look, it's a project that has had many delays. It’s frustrating for everyone involved, including me. However, the project is currently in a better spot. While we were operating it, Pemex was trying to ensure we had influence within that structure. We've brought in Grupo Carso, an enormous industrial player in the Mexico sector, who's helping out. The project needs the right plan in place and some engineering design work has taken longer. Yet it's at a point of effort to get it right, and I'm okay with that. We have several options that we are considering, but I think this delay, while not ideal, will yield the best results. As we plan to generate free cash flow, taking additional time to finalize details may be prudent.

So no CapEx this year toward Zama?

There’s some CapEx. Look, there's some real work happening—engineering design work is ongoing. There’s still a chance this could move a bit into 2024, but we don’t have to guide a material amount of CapEx, which is reflected in our guidance. You got it.

The next question comes from Jeff Robertson with Water Tower Research. Please go ahead.

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

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

Yes. The main updates we provided last quarter were that we've submitted permits for three wells at our Harvest Bend project in East Louisiana and for our White Castle project, which were deemed administratively complete by the EPA late last year. The State of Louisiana has since received primacy, giving them jurisdiction over those permits, which are now in the hands of the Louisiana Department of Energy and Natural Resources for technical review. We are pleased with that process and look forward to our discussions. Operationally, we are drilling a couple of wells with our Bayou Bend partners in that project.

For operationally, the business is moving faster than ever from a Bayou Bend perspective. We have permits progressing in Louisiana and are excited about the opportunities. But to answer your question directly, I can't identify any significant hurdles at the top of my head.

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. The team's worked really hard over the last few months, and I want to applaud them for their efforts. I think hooking up two wells with full subsea development from discovery to first oil in 13 months is a significant effort, and I'm proud of them and the execution. They did it safely without incident. At the same time, our business development team is putting together JVs that will impact how we think about our inventory in 2025 through 2029. We're super happy with what we accomplished in the QuarterNorth transaction and how accretive that will be for our shareholders. Many efforts occurred over the last 90 days, and while we might have ruined a couple of holidays, I appreciate how hard this team works. We hope this will be a year where you see lots of impact from these announcements on the business, and we look forward to discussing that with you all in future calls. Thank you for joining.

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