Talos Energy Inc

NYSE:TALO

Earnings Call Analysis

Talos Energy's Q4 Outlook and 2024 Strategy

Talos Energy forecasts Q4 production to reach 66,500-68,500 barrels per day, just meeting the lower spectrum of its annual guidance. Full-year operating expenses are on track, with 2023 CapEx projected at the lower end of $650-$675 million. Plugging and abandonment costs, influenced by inflation, are estimated at $120-$130 million. Looking ahead to 2024, capital investments will be significantly reduced, aligning with a strategy of prudent reinvestment for robust production growth, enhancing shareholder returns, reducing debt, and pursuing inorganic growth opportunities. This disciplined approach, paired with a strong credit position and upcoming production from new assets, is designed to maximize long-term shareholder value.

Reassurance on Financial Discipline Amid Expansion

The company has displayed prudence by keeping upstream capital expenditures at the lower end of its guidance, between $650 million to $675 million. This conservative approach is coupled with solid leverage metrics, as net debt rests at approximately $1.1 billion, with leverage at a comfortable 1.1x. The company emphasizes restrained spending, aiming to situate cash operating and G&A expenses toward the lower half of their respective guidance ranges of $410 million to $430 million and $90 million to $95 million. Free cash flow generation remains positive, with $9 million this quarter, further bolstered by a strategic $75 million liquidity injection from the partial sale of Talos Mexico.

Navigating Regulatory and Policy Challenges

Talos is actively addressing the complex regulatory landscape, including mandatory lease sales and winding energy policy, to continue its exploration activities in line with governmental directives. This includes dealing with frustrations around offshore leasing and engaging in litigation through trade groups to advocate for industry interests.

Strategies and Partnerships for Growth

Talos is strategically reducing capital expenditure in the next year to optimize cash flow generation. Despite decreased spending, the company foresees robust production growth, leveraging its recent discoveries such as Venice and Lime Rock, which are expected to come online to enhance output and revenues. Talos has fostered a partnership with Repsol, which will not only contribute to its financial muscle but also augment geological interpretive capabilities for future projects.

Long-Term M&A Focus

The senior leadership is keenly aware of potential M&A opportunities, with Talos positioned to maintain a vital level of liquidity to take advantage of such prospects. Additionally, sustained M&A potential is augmented by the company's skill set and strategy, though specific targets and timelines remain non-committal.

Continuous Investment in Carbon Capture and Storage

The emphasis on carbon capture and storage (CCS) projects as a future growth vector is evident, with current investments projected to be at or below the low end of the $70 million to $90 million range. Partnerships with companies like Chevron and Equinor in CCS initiatives hint at a proactive stance towards environmental responsibility and diversification of revenue streams.

Operational Updates and Outlook

Production for the fourth quarter is slated to be between 66,500 and 68,500 barrels of oil equivalent per day. Operational excellence is demonstrated by quick advancements from discovery to infrastructure setup, as with the Venice and Lime Rock developments, setting the stage for 2024 as a significant cash flow generation year. Drawing on its robust acreage position, Talos is ambitious yet cautious, looking to strategically manage rig market engagement while prioritizing risk management.

Earnings Call Transcript 2023-Q3

[Operator]

Hello, and welcome to the Talos Energy Third Quarter 2023 Earnings Conference Call.

[Operator Instructions]

Please note this event is being recorded.

I would like now to turn the conference over to Sergio Maiworm, Chief Financial Officer and Senior Vice President. Please go ahead.

[Sergio Maiworm, executive]

Thank you, operator. Good morning, everyone, and welcome to our Third Quarter 2023 Earnings Conference Call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive 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 our most recent annual report on Form 10-K and our quarterly reports on Form 10-Q filed 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.

[Timothy Duncan, executive]

Thank you, Sergio, and welcome, everyone, to our call. We appreciate you listening in. I plan to briefly cover some of the key operational highlights of the quarter and then turn it over to Sergio for final commentary ahead of Q&A.

During the third quarter, we were pleased with our advancements on several aspects of our business. We continue to advance our Lime Rock and Venice discoveries toward first production. We closed our previously announced Zama transaction in Mexico with Grupo Carso. We reached a new milestone with our first PPA Class VI permit application and filed our second EPA Class VI permit application for 2 additional wells.

So quite a bit was accomplished since our last call, and we're excited about the direction of our business. On the drilling and completions capital program, we are in the process of completing the Venice and Lime Rock wells before bringing them online in early 2024. Additionally, we are drilling another development well from our Lobster platform, which is successful to bring incremental production late in 2023 and help contribute to production growth in 2024.

Beyond our operator rig program, we are also participating in several interesting non-operated projects with our partners in the basin. The Marmalard well operated by Murphy, sand pay was successful over this past weekend. We expect production to commence in the first quarter of 2024.

The Odd Job Subsea pump project operated by Kosmos continues to progress and remains on track to be in service by mid-2024. Lastly, the Claiborne #1 well, operated by Beacon is scheduled for a rig intervention in the fourth quarter of 2023 to reinstate production in early 2024.

The third quarter is typically a quarter impacted by weather-related events. And even with a quiet hurricane season, loop currents unfortunately impacted our production and drilling operations during the quarter, requiring intermittent shut-ins of the HP-1 and associated infrastructure in the Phoenix and Tornado field. The impact of these loop currents caused a deferral of approximately 2,400 barrels of oil equivalent per day for the quarter in the Phoenix field, or 800 barrels of oil equivalent per day for the full year of 2023. The issues have since abated and production from the field is back online. The Claiborne non-operated well was also shut in during the quarter, contributing to an additional 1,200 barrels of oil equivalent per day of downtime in the quarter.

As we mentioned, the operator hopes to reinstate production in the coming months, so we should expect this downtime in the fourth quarter as well. Even with this downtime, as Sergio will discuss, the oil-weighted nature of our assets allowed us to maintain extremely competitive margins. And with several key wells being restored or added in the near term, we are looking forward to a strong exit of 2023, and an exciting start to 2024.

On the exploration front, Talos and Repsol signed a joint venture agreement to reprocess seismic data over 400,000 acres, of which close to 100,000 acres is controlled by Talos in a prolific area in deepwater Gulf of Mexico. We hope to develop an inventory of prospects to drill over the next few years could be tied back to Talos' infrastructure. This is an important development that we hope will generate significant value over time.

In Mexico, we are excited about our partnership with Grupo Carso, a conglomerate publicly listed in Mexico. In late September, we closed a previously announced sale of a 49.9% minority equity stake in our Talos Mexico subsidiary, which holds a 17.4% working interest, is up for approximately $75 million in cash at closing with an additional $50 million due upon first production for an aggregate price of $125 million. The deal established a baseline valuation for Talos Mexico of approximately $250 million while preserving significant upside to Talos' remaining 50.1%.

We expect Talos' strong operational track record, combined with Carso's critical local presence and global commercial reputation, will enable us to further advance Zama toward FID and first oil. We are working hard to progress towards FID following completion and final review of the engineering design work or FEED, securing project financing and final approvals.

We have always understood the importance this project has for local stakeholders in Mexico, and we are optimistic about the incremental value this project will create for our shareholders.

Turning to our Talos Low Carbon Solutions business. We are pleased at our first EPA Class VI permit application submitted in August for our Harvest Bend CCS project, where Talos owns a 60% interest received administrative completeness status in October. This first step of the EPA's permitting process determines that the permit application contains all the required information. The next step is a technical review.

Also in October, TLCS filed its second Class VI permit application for 2 additional wells at its Harvest Bend CCS project. TLCS aims to file additional Class VI permit applications in 2024 for its Bayou Bend CCS, Harvest Bend CCS and Coastal Bend CCS projects. Our first Talos operating offshore stratigraphic well at Bayou Bend is expected to spud during the fourth quarter of 2023.

As previously announced, the Bayou Bend partnership also expects to drill a Chevron operator onshore stratigraphic well in the first half of 2024. We also welcomed Equinor to the Bayou Bend partnership following its purchase of a 25% interest from Carbonvert, a transaction that further underwrites the quality of our carbon storage portfolio in Southeast Texas.

We are pleased with the news by the Department of Energy that they will invest up to $1.2 billion in a regional hydrogen hub in Texas, with the investment expected to be matched by key partners. This announcement outlines the benefits unique to the U.S. Gulf Coast and an expected and unprecedented growth in blue hydrogen production from the region, which will require permanent CO2 sequestration. Bayou Bend is in an advantaged position to help bring this sequestration ambition to reality.

We are continuing to explore capital raise for TLCS. We will continue to update the market as that process advances. While that is ongoing, we believe the operational execution in the carbon storage portfolio will help create long-term value for shareholders and enhance the marketing process.

Lastly, on the M&A front, we will continue to actively evaluate business development opportunities that fit our skill set and strategies, are accretive to our shareholders and preserve or improve our strong credit position. This spans tactical business development, bolt-on opportunities and larger strategic transactions.

In summary, it was a busy quarter, and we're pleased with the advancements we have made driving shareholder value creation in both our upstream and Low Carbon Solutions businesses. In addition, by focusing on operational execution, we successfully managed through the production and operation challenges associated with loop currents while continuing to use the excess free cash flow plus the proceeds secured in a partial sale of Mexico to keep our balance sheet in a healthy position.

With these key updates in our 2023 plans and goals, I will turn the call over to Sergio to address our financial details for the third quarter.

[Sergio Maiworm, executive]

Thank you, Tim, and good morning again, everyone. As a quick reminder that our consolidated results include the results of our upstream and Low Carbon Solutions businesses as further covered in our 10-Q filed yesterday. Where appropriate, I will highlight these impacts in these different businesses in my discussion of the financials.

During the quarter, Talos' generated production of 63,700 barrels of oil equivalent per day which was 76% oil and 83% liquids. This led to $383 million in revenue and $255 million in adjusted EBITDA in our upstream business alone. That equates to an EBITDA netback margin of close to $45 per BOE, which we believe ranks very high amongst public E&P companies.

The company also reported a net loss for the quarter of approximately $2 million or $0.02 net loss per diluted share. Our adjusted net income during the quarter was approximately $19 million or $0.15 adjusted net income per diluted share.

Capital expenditures, including plugging and abandonment and settled decommissioning obligations during the third quarter were $181 million in our upstream business. We also invested about $14 million in our CCS business, leading to a positive free cash flow generation of about $9 million in the quarter.

Additionally, we received approximately $75 million in cash from the Grupo Carso when we closed the partial sale of Talos Mexico in late September. CapEx in the third quarter, including spending on a few key items. First, we had ongoing operations related to completions, installation and hookups for Venice and Lime Rock. Second, the quarter included significant decommissioning spending on an inherited third-party project, which primarily drove the $38 million of spending for the quarter in that category. As laid out in our 10-Q, this spending in the third quarter completed most of our book liabilities in this category, and we do not expect this spending trend in future quarters.

Turning to our balance sheet. At the end of the third quarter, net debt stood at roughly $1 billion. The drawn balance on our RBL was $215 million on September 30 and liquidity remained very high at over $750 million. As we mentioned before, in September, we closed on the partial sale of Talos Mexico and received approximately $75 million in cash and those proceeds were used to pay down the revolver. The increased investment activity in 2023 continues to drive an increased working capital requirement in the business which we expect to abate in the fourth quarter and into 2024 as we significantly slow our capital investment pace. I'll address more of that slowing down in just a few minutes.

As of September 30, our leverage metrics stood at approximately 1.1x. I also wanted to provide a high-level overview of how we see the final months of the year progressing and how we're seeing 2024 shaping up. As outlined in our earnings release, we expect production for the fourth quarter to be between 66,500 and 68,500 barrels of oil equivalent per day, which puts us within guidance range for the year but towards the low end of our full year 2023 production guidance of 66,000 to 71,000 barrels of oil equivalent per day.

For the full year of 2023, cash operating and G&A expenses are tracking towards the lower half of the current range of $410 million and $430 million and $90 million to $95 million, respectively. CapEx including plugging and abandonment, settled decommissioning allegations and CCS investments are expected to be within our current guidance range.

Specifically, our upstream CapEx, including drilling and completions, asset management and other spending is tracking at the low end of the guided range of $650 million to $675 million. Our CCS investments are projected to be at or below the low end of the current range of $70 million to $90 million due to timing shifts of spending into 2024.

As I mentioned in the last earnings call, plugging and abandonment spending for the full year on our portfolio is coming in higher. It is now estimated to be between $120 million to $130 million primarily driven by inflationary pressures in that market as well as additional third-party decommissioning spending activity. We expect this category will normalize some in 2024 or we'll continue to fine-tune those estimates over the next few months. I'd also like to talk about how we're seeing 2024 starting to shape up. It's too early to go into specifics but philosophically, we see next year's capital investments substantially lower than 2023. We continue to evaluate the right levels of reinvestments into our business, and we believe that taking our foot off the gas on the CapEx side and taken a breather is likely the right path for Talos next year.

Despite this reduced investment, we still expect solid production growth next year, albeit with a tempered long-term growth trajectory. That allows us to increase near-term optionality for shareholder return, debt reduction as well as organic and inorganic growth opportunities. When weighing these options, we think this approach creates the most value for our shareholders.

Overall, I'm very excited about the trajectory of the business as we look to 2024. Our credit position remains very strong, and we are excited about new production early next year from Venice and Lime Rock as well as attractive investment opportunities in both our upstream and CCS businesses.

We believe the combination of attractive future investments, a solid balance sheet and an ever-present focus on M&A opportunities in line with our track record, will deliver and accelerate long-term value to Talos' shareholders.

With that, operator, we'll open the line for Q&A.

[Operator]

[Operator Instructions]

The first question comes from Nate Pendleton from Stifel.

[Nathaniel Pendleton, analyst]

Can you provide any thoughts on the further delay of the Sale 261 announced last week, specifically, how this impacts the industry and your expectations for any resolution there?

[Timothy Duncan, executive]

Yes. Look, it's interesting. It's -- we have part of the script and part of what we're talking about earlier is some progress from the Department of Energy on the CCS side. And it speaks to a little bit of a broader frustration when you have, I think, a government that's super supportive of one part of our industry and what we're doing to decarbonize, but then less supportive on the traditional forms of our energy. What we want and what we hope out of our regulators is they're not picking winners and losers.

And so the frustration, obviously, on the offshore side of the house, again, that's interior is that it feels like they're doing that. Now again, the Inflation Reduction Act in IRA requires us having lease sales, coinciding with the same year time frame is wind sales. And we know this government wants to have wind sales and we certainly are supportive of that. And we fully expect to have these lease sales.

But very frustrating to see this particular issue around the Rice's Whale and the idea that there's kind of the migration path of the whales moved from the Eastern Gulf of Mexico, where they're typically found to the Western Gulf of Mexico and arbitrarily falling in line across the basin. And then pulling out leasing. And so that's being fought by our trade groups, and it's appropriate for them to do so. We expect that to come back, and we hope it will. I think kind of further frustration is around the broad 5-year leasing plan where traditionally, that plan is always in place when the previous 5-year plan rolls out. This one was delayed 3 years into the administration, and then it's been kind of reinstated with less lease sales than the traditional plan.

So look, I think energy policy is important. I think it needs to be balanced. I think we all see and applaud some of the things happening on the low carbon side, and I think we're equally frustrated at what feels punitive on the traditional side. But again, part of the inflation reduction mandated these lease sales were prepared to lease in the upcoming lease sale kind of when it happens. We just got to go through this process.

[Nathaniel Pendleton, analyst]

Got it. And on the partnership with Repsol, can you provide any details about the earliest we could see? Any news from that reprocessing campaign? And if there are other opportunities similar to that one across your acreage?

[Timothy Duncan, executive]

Yes. Well, look, and I'm glad you brought that up. I can kind of go on long dialogues around federal government energy policy and not bring it back to where what do you do about it. And what you do about it is things of what we're doing with Repsol. And so what's interesting about that particular partnership is Repsol is coming to the table, not just wanting to participate financially and have a working interest in these projects. They want to actually participate in the geological interpretation of what's happening. They want to bring their expertise to bear and join us in trying to map through all this acreage.

And we have a host facility in Neptune. This is a combination of EnVen acreage and Talos acreage. So it's a way that we're trying to pull value out of a transaction in an acreage set that we didn't allocate value in when we bought the transaction. So all of those are very positive.

Look, I think this is more longer-term portfolio generation. These are types of prospects you see more in kind of the 2025 range and beyond. But it's absolutely the type of work that you need to do to make sure you're building inventory in the Gulf of Mexico. And when you have a built-in partner that's got that level of technical expertise, that's great.

The second part of your question, which is, are there more to do? Yes, I think there's 2 types of JVs. How do you find partners with the acreage you have? And again, when we closed in then, we were almost up to 1.5 million gross acres. And then how do you pull acreage from other parties that also want to say, look, I've got an acreage position, you have an acreage position. Let's pull that together and then let's try to build inventory out of our pooled acreage. And we're working some of those as well.

And hopefully, those will come to fruition in the coming months. So 2 ways to play it when you're trying to manage upcoming leasing or a lack of leasing, but you have a large acreage position, everybody else has kind of similar challenges and opportunities. How do you find built-in partners and how do you pull acreage and we're trying to do both in our business development activities.

[Operator]

The next question comes from Michael Scialla from Stephens.

[Michael Scialla, analyst]

I wanted to discern your decision to slow down here a bit. You were talking at one point about high single-digit production growth for a 3-year plan. You said you're tempering that a bit, but you still expect growth. So I want to see what you're thinking there. Is it low single-digit growth?

And maybe any indication on what the lower activity might lead to relative to what you're doing this year in terms of spending?

[Timothy Duncan, executive]

Yes. Let me give you some initial thoughts on that, Michael. Sergio can follow up with any of his thoughts. Look, this year, we really spent a lot of effort. When you think about something like Venice and Lime Rock, we discovered that less than 12 months ago. So installing all that infrastructure, doing that inside a year, it's been fantastic, but it's also a material amount of capital where you don't see any revenue and production generation out of that for a subsequent 12 months. And so I think we've had a rig on contract for the better part of the last 15 months, that will start to roll off when we wrap up this work with Venice and Lime Rock. And I think we want to see 2024 to be a material cash flow generation year.

And we think the first thing -- the first step in that is as we bring this new production on, kind of take our foot off the gas. Have a breather from a rig perspective, particularly in the first half of the year. And then as we kind of think about the second half of the year, right now, let's kind of reinstate some of our operated drilling kind of opportunities. You also have a rig market that's tightening. And I do think as we think about that, we look at -- one reason we've always kind of been a survivor in this basin and someone who's grown and thrived in this basin. As you look at those in the past, who didn't make it and sometimes it's because they didn't hedge, sometimes it's because they took on too big of a working interest in the project. Sometimes they just took on a bad rig contract over a long period of time and the commodity turnaround. So we haven't wanted to walk in to a long-term rig contract at these inflated prices. And so we might have to work with where there's rig opportunities and rig openings.

And so between wanting to take a breather after a long-dated rig contract that's rolling off, getting new production online, taking our time and thinking about what's the right way to play the rig market when it's hot, I think that just speaks to coming off the capital program substantially year-over-year and making sure we're really spending our efforts on generating free cash flow, which we can use to pay down debt ahead of potential refinancing.

So all sorts of ways to think about it. Look, as we wrap that up and those thoughts with the Board in the coming months and kind of roll out guidance for next year, we'll think about how that impacts, kind of broader production growth just on an absolute basis, but I think it's really around free cash flow generation in the near term.

[Michael Scialla, analyst]

Got it. Okay. And I guess on your production, I realize the fourth quarter is impacted by non-operated wells. Just wanted to get some more color on that, if I could. Is that intervention that the operator is talking about there? Is that something that's fairly routine? Or do you see that as carrying some risk that could affect that welcome-back-online in the first quarter of '24?

[Timothy Duncan, executive]

Look, it's fairly routine. I mean you have these big wells and these big completions and from time to time, you might have something happen downhole that requires either repair or sidetrack, obviously, a little different because you got to recycle that planning. If that happened in shallow water, if that happened in onshore, you can get on that pretty quick. It's pretty easy to move around resources and do that. When you do it in deepwater, it's just a different planning exercise. It takes more time. You've got to figure out how that typically fits in an intervention vessel or the rig you're using. So it's just a different dynamic.

But the idea that, hey, look, we got a large resource base and we want to either repair a well or sidetrack a well, look, that happens, I think, in everyone's portfolio through the course of the year. And so I think we're fully confident that comes back online.

But Mike, part of the guide on the fourth quarter, and we could have -- we probably should have been a little more specific about this was when we looked at bringing on Venice and Lime Rock in the first quarter, there's downtime related to ramp power to get those wells online. We're trying to accelerate that. We're actually seeing if there's a possibility we can sneak a little bit of that into the last parts of this year, which then pushes that downtime into this quarter. So there's a little bit certainly a non-op well that we want to get back online. There's 1,200, 1,300 barrels a day, net to our interest on a full quarter run rate there, and then there's some downtime related to ramp out that if we can push that really early into 2024, push that production, sneak a little bit into the exit rate, that downtime shifts into fourth quarter.

[Michael Scialla, analyst]

Okay. That's helpful. And I wanted to just ask one last one on Zama. Where do you stand with the FEED work there now? And I know at one point, you were debating between the FPSO and fixed platform, where's the -- how does that look at this point?

[Timothy Duncan, executive]

Yes. Look, it's an active discussion. I mean, I think part of the challenge in this has been time was lost and it's unfortunate. And the struggles around the initial formation of the unit. Our views on that, obviously, fairly well documented, frustration that we were giving up operatorship and then how do we kind of claw that back into the partnership to where we can build an integrated project team. And again, we've talked about that.

Keep in mind, when we were operator, we had a different development plan that Pemex was proposing when they took over operatorship and then we had to come up with a blend of that. Ultimately, the government reviewed that, and they approved the new blended plan, but there's some engineering details that underneath that, that we had to start over with. And so part of the pulling in the full unit and going through the process, ultimately led to changes in the design and some of that has to be kind of brought through the FEED. And then now it has to be thought through as we think about total capital and financing.

So some time was lost there, frustrated around that, happy though that we're back on track, happy to have Carso in. I think we're probably at a better place with that asset and with that partnership that we've ever been. Certainly, some of the debates and some of the frustration is behind us. And so now it's really more about a key focus on what do we need to do to wrap up. So still a little work there. Look, next year is an important year for that asset. It's been certainly been long enough. It's time to kind of get that thing to FID. It's time to get the ball moving on that. It's important to a lot of stakeholders. This is important to our shareholders. We're glad we've been able to monetize and realize some value. But we've got some work to do to get that kind of in the right spot. And again, I think we're in a better place with that asset than we've been over the last couple of years.

[Operator]

The next question comes from Subhasish Chandra from the Benchmark Company.

[Subhasish Chandra, analyst]

Just curious, as you have these 4Q events, these wells plus, of course, Lime Rock, Venice. What do you sort of anticipate as a base level of production, one that might not be subject to downtime, some of the 3Q hurricane effects, et cetera? But is sort of a number that you might bounce around offloads?

[Timothy Duncan, executive]

Well, Subhasish, thanks for calling. It's -- look, it's difficult to always find that perfect run rate in the Gulf of Mexico. I've always kind of said in the past, there's -- it's a basin where just by the nature of, and we answered in the last kind of question a little bit, you have something that when you have downtime, the ability to bring that back online isn't as quick as you see with some of the onshore operations or even back 20 years ago and kind of the predominant around our portfolio was in shallow water. So it's a little bit kind of tough to answer. Obviously, second quarter was a cleaner quarter. We were in the low 70s there.

And so good weather and typically a little cleaner. So I think we know what a clean quarter looks like. I think we know what projects we're trying to add on and then you kind of have these downtimes. So sometimes that downtime can be 2%, 3% in a quarter, sometimes it can be 10% in the quarter. The third quarter is always tricky. And what we're learning is loop currents, which generally around El Nino, that's now going to be forecasted into weather-related downtime.

And so I think the second quarter was a relatively clean quarter. It's a good way to anchor things, and then you have kind of what's the decline and then how do you stack on from there. And again, we have some things we're stacking on in the near term, more than just Venice and Lime Rock. The reason we put in some of those nonops and although smaller impact, smaller working interest, but we have 3 or 4 different operators out there actively in these activities. We had a nice little development well work over the weekend that also stack on into '24, which is another reason why we think we should focus on free cash flow generation and don't feel compelled to have to go at the pace we've been going at for the last 2 quarters in the first half of next year.

But I think second quarter was a good place to start. And then it's really what are we adding on in the next, what I would call 3 or 4 months. But as we look out in the total year, as we pull CapEx down next year, it may change how we think about the full year outlook, but we got to really ramp up that program.

[Subhasish Chandra, analyst]

Right. So as you -- I guess, the outlook for substantially lower CapEx, is that sort of an upstream comment that might be partly offset by a CCS spend? Or is that an enterprise comment?

[Timothy Duncan, executive]

I think more -- look, I think more of an enterprise comment. I mean, look, I think this year, as we -- last year in 2022, we generated a significant amount of free cash flow, paid down our debt close to $4, $5 of share or something of that nature.

This year, we knew we're going to generate as much as we really focus the capital program on putting some things online. And then we saw a little bit of a bubble in P&A with some non-op related stuff kind of associated with some bankruptcies. And so when you have a year, which I think we've done a pretty good job managing expenses and a pretty good job managing capital. So I want to make sure I make that point. But when you have a year where you're not generating as much free cash flow, you want to see yourself go back to that. And so that's the focus. And I think that's the focus somewhat mutually exclusive to CCS. Robin and her team, and we're happy to take questions around that or executing that, and there's a process around monetizing and bringing some value forward on that business as well.

I would call those separate. I think broadly from an enterprise perspective, how do we make sure the upstream business is generating the right levels of free cash flow, knowing that this was a year where we were going to really accelerate capital to some developments. We don't have to do that next year. You've got a rising rig market.

How do we want to manage all that and make sure that we're putting our shareholders in a place where we can be opportunistic as we were in some moments this year on buybacks and things of that nature.

[Subhasish Chandra, analyst]

Just one final one, if I can. So the number one question out there onshore is M&A. So we would like to give you an opportunity as well or A&D to comment what the offshore outlook looks like.

[Timothy Duncan, executive]

I mean, look, we get it. We understand how people are thinking about it. It starts with that free cash flow generation comment. I mean, we want to have a business to generate material amounts of free cash flow. We want, as we grow that business to have, as we add assets to be accretive to that goal, we know we want to scale and size. It's going to deliver capital back to shareholders. I mean, I think we all as executives understand what the model is. And M&A ultimately fits into that model if we can add the appropriate types of scale and diversity.

Our skill set is conventional geology, it's offshore operations. It's full life cycle, and if you step back from that and you think about our basin, we think our basin is filled with sellers ultimately. They may not be sellers in the next 6 months, but the majors may not want to own some of their assets across the life cycle. They may want to decarbonize. They may not be reinvesting at the rates they did 10 years ago. And so we actually think the Gulf is a great roll at play. And they've got to have a trusted counterparty. And we think we've passed that test. These guys are partners with us in our wells. We just can't predict when that's going to be. We've talked about looking outside the Gulf of Mexico because again, I think there's other companies thinking about this the same way we are. And so I would say, when you look at our skill set and you look at where we can transfer that skill set, I think it's in a pretty broad and diverse set of opportunities that are sustainable over the long run versus being in one unconventional play where you can see the ceiling of what's available for you to roll up.

So I'm bullish long term on how we think about M&A relative to our strategy and relative to our skill set from quarter-to-quarter and year-to-year. You just can't predict exactly how that's going to go.

[Operator]

Our next question comes from Jeff Robertson from Water Tower Research.

[Jeffrey Robertson, analyst]

Tim, a follow-up question on the Repsol joint venture. I think Talos is contributing about 97,000 acres to the 400,000-acre joint venture. Is Repsol contributing acreage? Is it an AMI in the area you all identify prospects you'll go and try to get the acreage? Can you talk about the mechanics of that?

[Timothy Duncan, executive]

Right. It's a combination of really more our acreage and more of an AMI concept. That's exactly right. That's how you should think about it. So we put a big halo around where our acreage is and where our key facilities are. And we say, look, amongst this area, let's go out and think about generating inside that acreage set. And then let's think about finding new opportunities around that broader AMI. So it's a simple concept. I don't believe I should double check they're contributing acreage. But really, it's -- we have close to 100,000 acres. We put a halo around that.

And part of that's commensurate with how you think about reprocessing seismic data, so you got the appropriate coverage from just -- from an imaging perspective. And then how do we want to kind of develop inventory around that entire kind of area of mutual interest or AMI for those that aren't familiar with concept. So that's how this comes together, Jeff.

[Jeffrey Robertson, analyst]

And with respect to M&A, are you seeing things? Or do you not necessarily seeing things today with some of the consolidation that's taking place in the industry, do you think that opportunities will present themselves in the Gulf of Mexico that Talos wants to have the strongest balance sheet possible to just have options?

[Timothy Duncan, executive]

Yes, for sure. I mean, look, I mean, part of wanting to make sure that we keep the leverage that where it needs to be, we try to have the appropriate levels of liquidity. I think even next year, I think what's the first use of proceeds on free cash flow. It's going to make sure we pay down debt. And then we can think of all the other capital allocation ideas of reinvesting in the business, having liquidity available for M&A. And look at some of these combinations, they're speaking to it directly. And so we don't know where that plays out. I think, for example, Chevron and Helix is a fascinating combination. As alumni, I think they certainly, the Gulf of Mexico is a core area for Chevron. But ultimately, what is the right asset mix for a company like Chevron or a company like Exxon. You don't know the answer to that, but you do know that if and when they might want to think about M&A, particularly on the asset side, they're probably going to want cash and they're going to need a counterparty that they trust. And what we have to do is be available to pass that test. While we look at other M&A idea -- that M&A ideas that might have more flexibility on sources and uses.

So we're thinking about it. Look, we certainly understand why you see the current trends. We're not rushing into anything, but we have to be prepared to be thoughtful on how we build out the firm and get to where we have a platform that's got more scale and diversity and ultimately leads to a shareholder return model that's sustainable.

[Jeffrey Robertson, analyst]

And a question on the CCS business. Does Equinor add anything that makes that project more marketable to potential anchor customers? And can you just, or maybe, Robin, can you just provide an update on where commercial discussions are with potential emitters?

[Timothy Duncan, executive]

Well, let me -- yes, look, I'm going to hand over to Rob. I think real quick on the conversation around Equinor, and then Robin will take it and provide her thoughts. When we set this up, I think the initial idea was setting it up in a way that it attracted the strategics, if you will. Not too different from what we just did in acreage. We can put together an acreage position but we're not going to go drill that $100 million subsea wells. We want a strategic involved in that with us to share that risk with us. And so Chevron came in now, and Equinor came in. So it's great to have the strategics there. And Robin can talk about the benefits they bring when we think about conversations with emitters and execution.

[Robin Fielder, executive]

Yes. Both partners have projects that are ongoing around the world. I mean, Equinor is one of the pioneers in CCS there in the Northeast. So certainly bringing that long-term experience and expertise to the project is a really great and encouraging thing. Both of our large partners, too, have the ability to go and invest in some of these other blue commodities as well. So I think that's exciting.

The announcement of the Department of Energy grant to the high velocity hub, which is surround the Southeast Texas and Southwest Louisiana region is very encouraging as we think about the counterparties here, the customers, what that grant will do is basically providing that integrated hydrogen ecosystem where we've got more investment coming into not just green hydrogen, but also being able to retrofit existing, gray hydrogen facilities and encouraging additional investment in new blue hydrogen facilities where the CO2 capture is actually designed on the front end.

And so we're having discussions with folks out of both categories as we're thinking about brownfield facilities, being able to address their CO2 emissions and some new greenfield investments. And so those conversations are ongoing, and we've got quite a few of those. And so we're very excited about continuing to advance that project. And as we mentioned in our release, still expecting to go drill that first stratigraphic well later this year in the offshore portion, which will help supplement our first permit for that project hopefully some time in 2024.

[Jeffrey Robertson, analyst]

Thanks. Tim or Robin, how long does it take to gather the data once you've drilled that strat well that you need to put in a permit application?

[Robin Fielder, executive]

Some of that data will be captured on site. We'll be logging the well itself and collecting some core data. We'll take some of that core that we're participating in the CCS consortium with that core lab pads so they'll be reviewing some of that. But we'll get some of that data in real time as we're on the location. Again, it's more supplementary to what we'd be filing. We already have the seismic coverage. We've got a model built, back that was part of our initial bid on that offshore, general and office lease back in 2021.

So we've got a great data set up there. This is more confirmatory and to really help supplement that application process as it goes into EPA and then hopefully, eventually, the Texas Railroad Commission as the state achieves primacy down the road.

[Operator]

The next question comes from Noel Parks from Tuohy Brothers.

[Noel Parks, analyst]

So just a couple of things. One thing I was thinking about is just the tiebacks that you have are so attractive from a capital efficiency standpoint. And I wonder, as you just were looking at planning over the next few years, what sort of inflation have you baked in or assume as you look at some of these prospects, I wonder if even Lime Rock and Venice, were they pretty much set in motion contracted before impact of the most recent inflation? Or are the examples of something also that might also be burdened by then?

[Timothy Duncan, executive]

I think it's -- look, a lot of it is largely driven by rig and the ancillary services around those rigs. You need the rigs to drill them. You need the rigs obviously to complete them on the ancillary services around vessels related to subsea projects and things of that nature. And look, there's demand around global subsea infrastructure installation. You're seeing it in areas like Guana, you're seeing it in areas like West Africa. So we certainly have to adapt to the market. I do think these time frames are typically when you think of these projects, you're thinking about them in somewhere between 18-month windows, 24-month windows. Now again, Venice and Lime Rock we accelerated. We did that because -- and we had long leads. And so once those are secured, you're not thinking about the inflation of tubulars and things of that nature.

So I do think one of the reasons we want to be thoughtful around the next round, we have an inventory that's got some quicker hookups, some development and then some broader exploitation and exploration. You've got to adjust to where that's going. And I think for us to say, "Hey, look, while we've been working really hard this year and had rigs on contract for the last 15 to 18 months, let's just step right into where the rig market is going."

I think our idea is say, look, let's take pause in the first half of the year. There's going to be some activity, but not as much operated activity. And then let's think about where this rig market is going and how do we play in it. And I don't think we play in it by being afraid of slowing down and feeling like we halved the speed up, and then we have to go take a contract over multiple years at a rate we haven't seen in the last 10 years. That's not probably the right responsible risk management decision for a company our size.

So we do think about inflation. We think about where -- if we're going to spud something in '25, what do we think the market is going to be in '25 and so we do that from a planning perspective. Sometimes you want to see, look, if we take our foot off the gas and maybe others, does that create maybe a flattening of that market. But there's a little, why don't we wait and see. And by waiting and seeing, we got to grab some windows instead of grabbing 2-year contracts, and we grab some windows.

[Noel Parks, analyst]

Right. I hadn't even been thinking of the sort of cooling next year of your spending around uncertainty in the service environment. But as you said, it seems like we're clearly entering one of the most uncertain environments we've seen a lot because we, of course, had this huge run-up. And then -- and now sort of unprecedented interest rate environment shift with us now looking ahead with China and everything, some pretty serious concern about maybe now as one of the recession hit. So all those combined certainly makes sense in the -- so I think maybe you're -- maybe even ahead of some other players in the industry with that thinking.

[Timothy Duncan, executive]

Well, I mean, look, I think it's just more what are the things -- what are the risks that you need to manage. Again, we're not a large cap. We don't have 250,000 barrels equivalent a day.

We don't -- that's what we aspire to become ultimately. But we are where we are. We're a company that was founded 10 years ago. And as we build these things in the Gulf of Mexico, we know where that risk management needs to look like. You need to have appropriate hedges. We've layered on some in the fourth quarter when we had run up in prices. And we still have a constructive price environment but you need to protect yourself from a commodity perspective, you need to protect yourself from a capital allocation perspective and a contract risk perspective. And those that haven't in the past haven't made it, and we've seen that. And that's not an offshore phenomena. That's an onshore in offshore phenomenon. We talked in the past, I think there's been over 300 bankruptcies in the last decade since we started this company.

So we think about that risk management a lot. And again, I don't -- I think we have to be mindful of where the market is. And if that changes a little bit of the trajectory of production growth ultimately brings down CapEx, but still generates meaningful cash flow. That's the right risk management strategy.

If you do have a little bit of uncertainty on what Fed is doing and things of that nature. But I think generally, we're constructive around the commodity. I think this is just what's appropriate risk management.

[Operator]

The next question comes from Kyle May from Sidoti & Company.

[Kyle May, analyst]

A couple of questions around the CCS business for Tim or Robin. You mentioned the first Class VI permits Harvest Bend reached administrative completeness. Can you give us an update on the overall expected time line for a Class VI permit now? And then what are the next steps for Harvest Bend?

[Robin Fielder, executive]

Yes, sure, Kyle. I appreciate the question. So yes, we filed our first application there at Harvest Bend in October. We received that administrative completeness. And so now it's entering what's called technical review. So we think that could last probably the next 12 or so months as they go through the details of that first permit. We did receive some early comments back on that first permit, then we were able to incorporate some of that feedback into our second permit, which is for an additional 2 wells. So we now have 3 wells sitting with EPA but also keeping in mind, we co-submitted that through the Louisiana Department of Natural Resources template as well. So we're all set up, hopefully, as the state achieved primacy sometime next year for a very smooth transition over to that regulatory agency.

Again, the plus of primacy is you've got a state that knows our geology very well, lots of resources. And we've seen demonstrated in the 2 states that have it, the speed of that turnaround to really increase. North Dakota has actually a CCS project that just started up this past week after a permit made it through in less than 6 months. So we're very encouraged that when the states take over, we can get these on to a more timely time line, but regardless, even if it's 2 or 3 years to process through EPA, it fits within our overall project time lines.

[Kyle May, analyst]

Got it. And then Bayou Bend, you're planning to spud another -- or planning to spud the first well in the fourth quarter. What's the estimated cost for a well now? And how long do you think that's going to take?

[Robin Fielder, executive]

Yes. So we'll be spudding that first stratigraphic test well. This is a data acquisition well where we're going to be doing pretty extensive logging and core collection again, to help calibrate our model, but really supplement that first application that will go to EPA and also eventually into the railroad commission as we'll take a similar approach there keeping both agencies in the loop.

As far as the cost there, I mean, it's going to depend for that one being offshore, obviously, there's a little bit more costly to get a jackup or it to go drill that. That's what we're waiting on right now is the rig is still with another operator. As you do these onshore, they're fairly straightforward wellbores. We're talking a vertical wellbore from the range of 6,000 to 8,000 feet. So nothing very sophisticated, and that's -- the main cost difference will be if we decide for these wells to become keeper wells, where we're going to reutilize that wellbore for either monitoring an injector. Because if we do that, we'll run a corrosive resistant pipe in those sections or if it's just a pure data acquisition well, you can just suspend the well and P&A to be much less costly. So it really depends on where we're at and what that is. But as far as the overall investment in the CCS projects, the drilling of the wells is one of the smallest pieces.

[Operator]

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

[Timothy Duncan, executive]

Thanks for joining the call, everybody. I think one of the themes in this quarter is, obviously, third quarter is always a noisy quarter with respect to potential downtime related to weather. We saw that, we're trying to have a strong exit. We're pulling as much value forward as we can. We're trying to get some wells online. We're trying to pull value forward in our TLCS business, we pulled value forward in our Mexican asset. And so I think it's been a year of really trying to do the blocking and tackling that it's going to take to create long-term value. And so we talked about next year. Next year, I think we're going to focus our attention on materially more free cash flow generation than this year as we've had a -- what I would call a moving year.

So I think we're happy with where the business is. There's a lot of work to do. There's a lot of things to get online, a lot of more value to pull forward. But I think we're trying to do the right things. And as we think about joint venture structuring, on building long-term inventory development as we think about the initiatives again to pull value forward on these catalysts. I think the team is doing the things that it needs to do is going to generate value. We're looking forward to kind of a strong exit and a robust start to 2024 and being in touch with the investor community on how that's going. So thanks for joining the call.

[Operator]

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