Welcome to the First Quarter 2024 ConocoPhillips Earnings Conference Call. My name is Liz, and I will be your operator for today's call. I will now turn the call over to Phil Gresh, Vice President, Investor Relations. You may begin.

Thank you, Liz, and welcome, everyone, to our First Quarter 2024 Earnings Conference Call. On the call today, we have several members in the ConocoPhillips' leadership team, including Ryan Lance, Chairman and CEO; Tim Leach, Adviser to the CEO; Bill Bullock, Executive Vice President and Chief Financial Officer; Andy O'Brien, Senior Vice President of Strategy, Commercial Sustainability and Technology; Nick Olds, Executive Vice President of Lower 48; and Kirk Johnson, Senior Vice President of Global Operations. Ryan and Bill will kick it off with opening remarks, after which the team will be available for your questions. A few quick reminders. First, along with today's release, we published supplemental financial materials and a slide presentation, which you can find on the Investor Relations website. Second, during this call, we will make forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings. We will make reference to some non-GAAP financial measures. Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website. And third, of course, when we move to Q&A, we will be taking one question per caller. So with that, I will turn it over to Ryan.

Thanks, Phil, and thank you to everyone for joining our first quarter 2024 earnings conference call. It was another solid quarter of focused execution across the portfolio on our strategic plan. Starting with our international projects, we continue to ramp up production at Surmont Pad 267 in Canada, Bohai Bay 4B in China, and 3 subsea tiebacks in Norway. We expect to start up the fourth subsea tieback in Norway in the next month. In Canada at Montney, production reached a new record level following the start-up of the second central processing facility, leading to over 20% growth versus the fourth quarter. Shifting to our other projects, we are wrapping up a successful first major winter construction season at Willow this week, and module fabrication is going according to plan. As we build out our LNG portfolio, our Qatar and Port Arthur projects are also progressing well. Moving to the Lower 48, our primary focus remains on capital-efficient growth as we continue to improve efficiency in drilling and completions. For 2024, we still expect to deliver low single-digit production growth at flat activity levels with lower capital spending versus 2023. Shifting to return of capital, we remain on track to distribute at least $9 billion to shareholders this year, and we announced a VROC of $0.20 per share for the second quarter, consistent with our guidance of a 60-40 split between buybacks and cash distributions for the year. To wrap up, it was a solid start to the year. We are on track with the full year guidance that we laid out back in February, which anticipates a well-balanced growth across our global portfolio. And as we discussed in our Analyst and Investor Meeting last year, we continue to invest in our deep, durable, and diverse asset base, which will drive significant cash flows and shareholder distributions over the course of our 10-year plan. Now let me turn the call over to Bill to cover our first quarter performance and 2024 guidance in more detail.

Thanks, Ryan. In the first quarter, we generated $2.03 per share in adjusted earnings. We produced 1,902,000 barrels of oil equivalent per day, representing 2% underlying growth year-over-year. Lower 48 production averaged 1,046,000 barrels of oil equivalent per day with 736,000 in the Permian, 197,000 in the Eagle Ford, and 96,000 in the Bakken. Now this included a 25,000 barrel per day headwind from weather, which impacted Lower 48 production by about 2% and was slightly higher than the 20,000 barrel per day guidance provided on the fourth quarter call. As a result, Lower 48 underlying growth was roughly 1% year-over-year. Now for the rest of the company, Alaska International production averaged 856,000 barrels of oil equivalent per day, representing roughly 4% underlying growth year-over-year, excluding the Surmont acquisition effects, and this really highlights the benefit of our diversified global portfolio. Moving to cash flows, first quarter CFO was $5.1 billion, which included APLNG distributions of $521 million. Capital expenditures were $2.9 billion. Debt retirement payments were $500 million, and this was partially offset by proceeds of $200 million from the disposition of non-core assets. And we returned $2.2 billion to shareholders in the quarter, including $1.3 billion in buybacks and $900 million in ordinary dividends and VROC payments. We ended the quarter with cash and short-term investments of $6.3 billion and $1.1 billion in longer-term liquid investments. Turning to guidance, we've maintained our full year production outlook of 1.91 million to 1.95 million barrels of oil equivalent per day, which translates to 2% to 4% underlying growth. And for the second quarter, we expect production to be in the range of 1.91 million to 1.95 million barrels a day equivalent, also which represents a similar 2% to 4% year-over-year underlying growth. Our full year turnaround forecast is 30,000 barrels per day. This includes 25,000 barrels per day of turnarounds in the second quarter, primarily in Alaska, Norway, and Qatar, and 90,000 barrels per day for the third quarter. And as we mentioned on the last earnings call, the heavy third quarter maintenance was driven by our once-every-5-year turnaround at Surmont. For CapEx, our full year guidance remains $11 billion to $11.5 billion, with a greater weight to the first half of the year. This is due to the $400 million of equity contributions at Port Arthur LNG that are almost entirely in the first half of the year, as we discussed on the last call. For APLNG, we expect $300 million of distributions in the second quarter with no change to full year guidance of $1.3 billion. And finally, for the second quarter, we're forecasting a $600 million working capital outflow related to tax payments and timing in the U.S. and Norway. All other full year guidance items are unchanged. So we continue to deliver on our strategic initiatives. We remain focused on executing our plan for 2024, and we're committed to staying highly competitive on our shareholder distributions.

Our first question comes from Devin McDermott at Morgan Stanley.

I wanted to ask about Alaska. You noted that you just completed the first and are completing the first winter construction season for the Willow project. I was wondering if you could give us a little bit more detail on what was completed this past winter, how it went versus plan? And as we look ahead, what are some of the next key milestones we should be focused on for the project.

Devin, this is Kirk. Yes. So we had a really strong start to project execution here on Willow this year. We were actively closing out here this week, actually our first major winter construction season on the North Slope where we were able to successfully mobilize over 1,200 workers and were able to successfully build out 7 miles of gravel road, 30 miles of gravel pads, and 30 acres of gravel pads for future facilities. We've successfully constructed all of the pipelines that we planned for this winter season. Certainly, in addition, module fabrication has continued to progress really well here this winter and this spring, and we're expecting to be ready to transport the first of those modules to the North Slope here on schedule in midyear, which is the Willow operations center. We still expect to be in the range of $1.5 billion here for 2024 and the progress that we're making here this year gives us confidence to keep our estimate on total capital to first production as being unchanged. So we're still in that $7 billion to $7.5 billion range. And again, that's underpinned not just by the progress that we're making here on construction this year, both on the North Slope and our offsite module fabrication. But we continue to make some really strong progress on our contractual scope. We've landed three-quarters of our total project scope here to date, and we have an expectation that we could be upwards of 90% of our total scope contractor here by year-end. As we look forward here for the remainder of the year, obviously, we're going to continue off-site module fabrication for production facilities, and then we'll continue to ramp up both procurement and certainly prepare for the follow-on winter construction season. So again, great progress here on the Willow project this year and putting us in a really strong position. We do these projects a lot in Alaska, and it's great to see the teams making the progress they are here yet again this year.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

I wanted to spend some time talking about the return of capital, and it is notable in the release you talked about at least $9 billion. So just your framework for thinking about what the right level of return of capital is early in the year. Oil prices have been volatile, natural gas prices have been weak, but certainly, you have a terrific balance sheet and have the capacity to raise that number. So I'd love your perspective on that.

Yes. Thanks, Neil. No, I think we want to divestiture. Look, we believe we're in good shape with the $9 billion that we described early in the year. I think you look at a reasonable percentage of our cash flow through the first quarter of this year, similar to what we've done in years past. We recognize that the price that we're experiencing today is well above our mid-cycle. So our investors should expect well above 30% of our cash flow going back to them. We're monitoring kind of the volatility, as you mentioned, Neil, and again, it's not just sort of in WTI or Brent markers, it's in all the markers, NGL, LNG, and natural gas as well. So it's a function where we just want to see some durability to some of the prices to see where they end the year, and you can expect to get a fair percentage of our cash flow return back to our shareholders like we've done over the last number of years.

Our next question comes from the line of Lloyd Byrne with Jefferies.

Ryan, can you just comment strategically on the Permian gas and just kind of how you see that playing out? You guys have been really proactive in integrating some of that gas and looking forward, but any target levels you have? And maybe just how you're thinking about some of those differentials.

Yes. Thank you, Lloyd. Bill has some information that he can share. I agree that we have been considering this for several years, aiming to develop an LNG strategy to enhance our commercial activities, particularly regarding the gas we transport in the Lower 48 to take advantage of the opportunities that are still available. I will let Bill provide more details on that.

Yes, sure. Lloyd, so as we talked about in the past, we have shipped to multiple markets. We've got transport capacity to the Gulf. We've got transport capacity on the West Coast. We're very supportive of offtake capacity from the Permian Basin. In fact, we do have some firm capacity on the upcoming Matterhorn pipeline, but a sizable portion of our volume also is exposed to prices and in-basin pricing. We don't disclose what percentage moves to each location for commercial reasons. But a really good way to think about the company's realizations is as a percentage of capture of first of month Henry Hub pricing that's what we show. First quarter, we were about 70% realization. That was a little bit higher than fourth quarter, so in a good position. And obviously, the Permian Basin has got some transitory issues right now with gas pricing; you're starting to see pricing go negative towards the end of the first quarter and as we go into the second quarter. So I think everyone is expecting to see a lot of volatility this year. We certainly expect realization in the second quarter to be particularly low, but these are transitory, and as we come out the back of the year with takeaway capacity, we expect that to return to more normal levels. And as you know, we've got a very sophisticated gas marketing organization. We are moving several multiples of our equity production, so our flow assurance is very good for the company, and we've got access to competitive market pricing. And that flow assurance really is important because we don't routinely flare, and we want to be able to continue to produce mix; we've got strong return profiles in the Permian, primarily driven by oil.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

I'd like to take a look at the Lower 48 activity. Obviously, 1Q is down a little bit just because of the weather, but can you give us some color on how you see that progressing through the year? Should we see a nice bounce back in 2Q and then that steady kind of slow single-digit kind of rise through the course of the rest of this year?

Yes. This is Nick. I'll provide you with an update on the Permian in the Lower 48. We faced some challenges due to weather downtime, as Bill mentioned earlier. Excluding weather impacts, we saw about 3% year-over-year growth. Additionally, we experienced some effects in Q1 from the operational frac gap at Eagle Ford because wells came online in the latter half of Q1. Overall, in the Permian, we are focused on driving efficient operations, maintaining flat activity with rigs and frac crews, although we may see quarterly increases. The first half of our development plan in the Permian is centered on the Delaware, while the second half will shift towards oil-weighted projects in the Midland Basin, where we have significant pad projects and three-mile laterals coming online. Our teams are fully focused on capital efficiency in both drilling and completions, with positive outcomes from simul-frac and remote fracs leading to efficiency improvements in frac operations. On the drilling side, our real-time drilling intelligence team is monitoring the rigs 24/7, which is promising. In terms of efficiency, if you consider the weather impact that Bill mentioned and the effects of the Eagle Ford frac app, Q1 might be the lowest production point for the year, with expectations for progressively higher production in Q2, Q3, and Q4. We have larger pad projects scheduled for the second half of the year in the Midland Basin, indicating a favorable production trajectory. Overall, our outlined plan targets low single-digit growth within the 2% to 4% range.

Our next question comes from the line of Betty Jiang with Barclays.

Nick, you set that up for me really well because I want to follow up on the Permian and then the efficiency gains that you guys are seeing. We are hearing from other operators significant efficiencies from e-fracs and longer laterals. I would just love to get more color on what you guys are seeing and how that's tracking versus the corporate plan and importantly, how that's getting translated into the capital efficiency that you're seeing in the basin relative to plan?

Yes. Let's discuss the longer laterals. I previously mentioned our operational efficiency with frac spreads and drilling. Our teams are concentrating on long lateral development as we progress. To remind everyone, in our Permian inventory, 80% of the laterals are 1.5 miles or longer, with 60% being 2 miles or more. For 2024, 80% of the wells will again be 1.5 miles or greater, and about 20% will be 3-mile laterals. Some of these longer laterals are set to come online in the second half of this year. We are witnessing a cost of supply improvement of 30% to 40% when transitioning from a 1-mile lateral to a 3-mile lateral. This demonstrates our efficiency improvements. Specifically, in the Midland Basin, we've achieved internal record wells, with impressive performance from spud to rig release over the last 3 months. We're focused on increasing the number of feet per day, more stages per day, and more pumping hours per day. We have seen a 10% to 15% increase in pumping hours from 2022 to 2023. All of this contributes to improved capital efficiency, thereby reducing your cost of supply. It's very encouraging across the board.

Our next question comes from the line of Roger Read with Wells Fargo.

Maybe, Ryan, just get your updated thoughts on the global LNG market. You've obviously got a pretty good footprint; you're expanding it here. Just how you're thinking about it over the next, let's say, 2 to 3 years as some of these newer projects come online?

Yes. Thanks, Roger. I'll take a shot and maybe let Andy chime in a little bit as well. But as I said earlier, I think we certainly step back to a few years ago and wanted to continue to grow our LNG exposure in that position. We know the markets, we have our own technology, we know the business quite well, and we do have a strategic intent to continue to try to grow that. And it's really participating in all facets of it: the production side here in North America, in Qatar, in Australia, being in the liquefaction side here in North America and elsewhere, having ships and being in the regas potential as well. So trying to grow that integrated business as well even at sort of the lower Henry Hub prices you see today, the arb is still open to make money and make a decent rate of return as you move some of that LNG to Europe and to Asia. It's a long-term business that we're interested in. So I can let Andy chime in on a few more specifics as well.

Yes. Thanks, Ryan, and thanks, Roger, for the question. I think this is a bit of our business that I don't think is completely understood. So it might be helpful if I just put sort of some of the details around it. As Ryan said, if you go back all the way to 2022, we increased our ownership on the resource side with taking more equity in APLNG. And then we've also participated in the two Qatari expansion projects. And I think where you were specifically going with your question on really more from the commercial perspective. So on the Gulf Coast, we've secured 5 MTPA of offtake from Port Arthur, and we also have a 30% equity interest there. We've also secured offtake on the West Coast of Mexico with 2.2 MTPA of Saguaro LNG, and that one is pending FID and 0.2 MTPA of offtake for 5 years starting in 2025 from ECA Phase 1. So all in, our offtake in North America is about 7.4 MTPA pending the FID at Saguaro. Then switching to the regas side of things, we now have 4.5 MTPA secured in Europe. This includes 2.8 MTPA of capacity at the German LNG. Now up to 2 of that will support our LNG SPAs with Qatar, and we also have 1.7 MTPA of regas capacity at the Gate Terminal in the Netherlands. So over the near term, our focus is on continuing to ladder in the regas opportunities. And over the longer term, maybe think about 10 to 15 MTPA, has a good range of offtake capacity to think about. This will allow us to achieve the full benefits of scale across our organization. I do want to be clear: this is an offtake ambition. We don't feel that we have to take on additional liquefaction capital. So for competitive reasons, we don't get into the specifics of where we're actually developing offtake and regas right now. But needless to say, that's something that's front of mind for us. So I know that was a lot of detail, but hopefully, that helps everyone sort of just frame up sort of the moving parts we have going on in the LNG business.

Our next question comes from the line of Nitin Kumar with Mizuho.

Ryan, there's been some news reports saying that linking you to a potential bid on the Citgo refining assets. There were also some articles and notes saying that you're considering the sale of part of your equity interest in LNG. I'm not going to ask you to comment on specific transactions. But as you look at the portfolio today and the evolving macroeconomic outlook, are there opportunities for portfolio optimization? And maybe you can comment on a few of them.

Yes. Thanks, Nitin. I'd say, first, now on the Citgo, we're watching that process. Look, we're a creditor in that process. So we own quite a bit of money from the Venezuelans, so we're watching that process pretty closely. Look, we're not trying to become an integrated refining major with refining in our portfolio. This is the way to protect what's the company and the credit that we have against the Venezuelan government. So we're watching that and following that process pretty closely, but that's to get the money that they owe us for the judgments that we have against the Venezuelan government for the expropriation of our assets. Look, we're obviously optimizing the portfolio. I think in the last call, Andy mentioned the acquisition of some APLNG interest a couple of years ago. We've secured the full interest at Surmont here in the last year. So we're always looking at opportunities that make the company better. Those are two great opportunities that came along at the right time, and we were at the right place to add to the portfolio. We think about the disposition side; we sold assets over the last couple of years where they don't compete in the portfolio and our cost of supply thresholds. Then the team knows that they need to improve or move out of the portfolio, and we do that constantly. We don't have any major large disposition programs that we're thinking about inside the company. We just do that as a normal course of business just to improve the company. With regard to Port Arthur, look, we've had some inbounds on the equity interest that we have, and we're taking a look at that, trying to understand what's right for the company going forward. As Andy mentioned in the last question, look, we don't necessarily need to be an equity owner in these things. We wanted Port Arthur to launch the project in Phase 1, so we did that. But we're not married to it if the right opportunity comes along. So we continue to look at those opportunities at all. We're in the market every day, and we're trading in the market, and we're looking at the market and doing things that we think make the company better.

Our next question comes from the line of Paul Cheng with Scotiabank.

AI is a buzzword in many other sectors, but we haven't heard the producer talking much about that. But one of the largest oil services companies in their conference call just talked about how they believe their revenue will be up because there's a lot of interest in their product using AI that will improve the EUR and well productivities. You guys are always on the cutting edge and trying to improve those aspects in the shale. Can you tell us, is it being openly optimistic or in the next 2 to 3 years or 3 to 4 years, do you actually think the AI is going to help you dramatically improve your EUR or well productivities, or is this really much longer-term, maybe at some point it will happen?

Thank you, Paul. I believe AI is set to revolutionize our industry and many others globally. Nick previously mentioned our advancements in the digital realm concerning data and automation and how we're working to enhance our company and operational efficiency. While I can't comment on what was said during another conference call, I do think AI will significantly impact our business, particularly regarding the speed of our learning curve. If we can optimize our learning processes and effectively apply deep machine learning, it will make a difference. I'm viewing this as a way to accelerate our learning curve, which will improve our effectiveness and efficiency across the entire company—not just in technical and operational areas, but also in back-office functions. The challenge lies in implementing deep machine learning in an enterprise like ConocoPhillips and in similar large companies worldwide. We need to transition from retail applications to large enterprise settings, managing vast amounts of data to achieve better efficiency. So yes, AI will enhance our operations and make us better, but we need to ensure that everyone in the company embraces our initiatives in this area.

Our next question comes from the line of Ryan Todd with Piper Sandler.

Maybe just to follow up on some of your LNG conversations from earlier; you clearly talked about there's still work ongoing on the commercial and marketing side and building out some of those things. Is there still appetite to add on the supply side? Qatar announced another LNG expansion in North Field West. Is that the type of thing you'd be interested in, more of that in the portfolio or more supply-side LNG within the portfolio? And then are you seeing signs of cost inflation on global LNG projects? What are you seeing as you look at the development of your LNG liquefaction trends across the portfolio right now in terms of cost inflation?

Yes, thanks, Ryan. I believe Andy has laid out our goal to achieve between 10 million to 15 million tons, but the volumes Andy mentioned do not meet that target. So, do we aim to grow further in this area? Absolutely. We are focused on being in the right locations with the right opportunities, and North America is promising, especially on the Gulf Coast and West Coast if good opportunities arise. It's crucial to have the best liquefaction fees and to pursue better projects. Regarding Qatar, we have successfully secured interests in a couple of trains with NFE and NFS, and if they offer more opportunities with competitive terms, we are interested in deepening that relationship in the future. We will wait to see their decisions on any future expansions from the North Field. Our relationships and participation there are strong. In some areas, the execution at Port Arthur is progressing well, and we have no concerns regarding inflation or related issues. We are closely monitoring the liquefaction expenditures and potential future developments, but we feel confident. We are engaging in these projects because they are competitive within our portfolio and align with our long-term strategic vision for the company.

Our next question comes from the line of Neal Dingmann with Truist Securities.

My question is around your Lower 48 marketing associated realized prices. Specifically, you suggest on Slide 6 that your Permian differentials remain maybe a little bit pressured. I'm just wondering, are there any changes you can make on the marketing side to continue to stabilize and improve this? I know you've materially done this, of course, since you bought the Concho assets versus what they sort of just accepted at the wellhead. So I'm just wondering, are there further improvements or things that you potentially could do on the marketing side to even see even more improvement on the realizations.

Yes, Neal, this is Bill. As we talked about, we have offtake capacity both to the West Coast and the Gulf Coast, and we're interested in additional takeaway capacity on Matterhorn, like I talked about, so we are constantly looking for ways of optimizing that portfolio. Our commercial organization is in the market daily. We're doing orders of magnitude on that production. So we really have a good sense of where volumes are moving and what rates are going. I think that the improvement on margins, as you're looking at that, is really going to come down to getting additional takeaway capacity coming out of Permian. As we've gone into the second quarter, we've had some maintenance going on there with El Paso and a couple of other pipelines and a couple of outages that's putting pressure on Waha pricing. I think everybody has been seeing that. That will likely clear through the system here as we go through this quarter. But the real relief doesn't come until you get additional takeaway capacity here towards the third quarter with Matterhorn coming online. At that point in time, I would expect that you're going to see more normal differentials, and you're going to see a return for our portfolio at more than about 80% of capture of Henry Hub across the portfolio. So I think it's a transitory type thing that you're seeing until you get additional pipeline capacity built, and so I think the important thing here, again, is that flow assurance matters at a point in time where you're constrained in the basin, and we've got excellent flow assurance given our commercial capabilities.

Our next question comes from Bob Brackett with Bernstein.

In the prepared remarks, you mentioned the new pad at Surmont 267. And I recall under the old operating structure, the partner wasn't that eager about new capital, the new technology. Clearly, now you control the pace. Can you talk about that pad? How different is it technologically than some of the older pads? And what are you seeing in early results?

Bob, this is Kirk. Yes, first, I'll probably just start out by saying our operational performance this past year has been really strong, and that's important having come through the acquisition of our remaining 50% interest in that asset. And of course, we brought on that new pad. Certainly, as you've heard from us before, first in on 267 and started earlier this year. Then we achieved first oil in December, and we've been seeing a really steady, strong ramp on Pad 267, having started that in December here through the first quarter. Production for the first quarter is up 3 MBOE, and we really have just seen 267 start to grow, and we expect that to continue to offset decline, especially when we normalize that for the third quarter turnaround that we have coming up. Bob, you've also heard from us in the past, we've spoken to the fact that we intend to add about a new pad about every 12 to 18 months, so about every year. We just continue to find new efficiencies and new opportunities as we bring that pad online. It's really performing against our expectations. The team spent a lot of time as we've done a lot of infill work, mitigating base field decline. We've experimented with a number of technologies around our liners, and we have prospects of drilling longer laterals here in the future as well. So expect to hear more from us on this front. But certainly, Pad 267 is coming in strong, and I'm really just pleased with how this is shaping up and our ability to continue to grow the asset here in the future, having control of it.

Our next question comes from the line of Alastair Syme with Citi.

Can I come back just again to the question of the lower gas prices because I'm not really sure I understand whether you're making any near-term changes to your capital program? I'm thinking both the Permian and the Eagle Ford here, given that low prices must surely be impacting on near-term cash flow.

Yes. Yes, also, we're not making any capital allocation decisions. It's all driven by the liquid side of the business. I think, as Bill articulated, we need more takeaway capacity out of the Permian to get the Waha prices back up, and we're advantaged a bit because we have El Paso volumes that we can take to the West Coast. They've been in a bit of a turnaround as well and some maintenance activities going on that pipeline. So there's a dynamic happening in the basin that is impacting Waha prices. So again, as Bill said, getting your gas evacuated is pretty important, so you don't go flare because we're not going to routinely flare gas; we've made that commitment. So having the takeaway is really, really important in these periods, and then having the flexibility with your commercial team, we know where we can get a premium price, and we're after that every single day.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

I wanted to ask on the first quarter capital trajectory. If I remember correctly, you had soft guided to over $3 billion of capital for the first quarter, but you came in lower at $2.9 billion. Can you bridge that gap for us? And is this lower CapEx, the result of just timing? Or is there anything structural that could carry forward?

This is Andy. Yes, I can take that question. It's a pretty simple answer. As you said, we came in at $2.9 billion for the quarter, which was slightly less than our guidance. That slight underspend was a result of some Willow capital shifting from the first quarter into April. So if you exclude that timing, our capital spend came in accordance with our expectations. Now as you look ahead to the second quarter, capital is expected to be slightly higher than the first quarter driven by PA LNG and the Willow timing. And then as you look forward to the second half of the year, capital is expected to be lower than in the second half than the first half, primarily due to the $400 million of Port Arthur LNG equity capital spend that rolls off as we go into project financing.

Our next question comes from the line of Leo Mariani with ROTH MKM.

I was hoping you could speak a little bit more to the expected trajectory of your Eagle Ford volumes. I know you had kind of the frac holiday a bit, which kind of impacted volumes in the last couple of quarters. I know they've been kind of trickling down here. I guess is that over? Do you have more of a normal activity cadence? And should we start seeing growth in those volumes as we roll into the second quarter and the second half of the year?

Yes, Leo, just for the group, again, we did take that frac gap, as you just mentioned, in the second half of 2023, that impacted 4Q and has also impacted the first quarter of this year because the wells coming online after we reinstated that frac crew came online in the second half of the last quarter. So we're not only going to see that until you hit 2Q. Again, we took that frac gap because of just the strong operating efficiency that we're seeing in the fracs versus the drilling side as we apply the different technologies out there. So that's a good thing. Looking ahead, just to 2Q and beyond, we expect to see higher production from the previous two quarters as we bring those wells online and had reinstated that frac gap. So this is all in line with our full year guidance and is consistent with the production growth that we laid out. Again, that's low single digits in that 2% to 4% range.

We have no further questions at this time. Thank you, ladies and gentlemen. This concludes today's conference call. Thank you for participating. You may now disconnect.