EOG Resources, Inc. — 2024 Q1
Transcript
Each turn shows the speaker, their inferred role, the section, and that turn's net sentiment (×1000).
Good day, everyone, and welcome to the EOG First Quarter 2024 Earnings Conference Call. As a reminder, this call is being recorded. [Operator Instructions].
Good morning. And thank you for joining us for the EOG Resources First Quarter 2024 Earnings Conference Call. An updated investor presentation has been posted to the Investor Relations section of our website and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today.
Thanks, Pearce. Good morning, everyone, and thank you for joining us. EOG is off to a great start in 2024, both delivering value directly to our shareholders and investing in future value creation. Primary drivers of that value are EOG's commitment to capital discipline operational excellence and leading sustainability efforts, all underpinned by our unique culture.
Thanks, Ezra. Given the recent strength in commodity prices, we have updated our 2024 forecast to reflect $80 oil and $2.50 natural gas for the remainder of the year and now expect to generate $5.6 billion of free cash flow for the full year.
Thanks, Anne. I'd like to first thank all the employees for a great start to the year with safe and efficient operational execution. Our first quarter volumes and total per unit cash operating costs beat targets while capital was in line.
Thanks, Jeff. We're very happy with the results of our first 3 packages of development wells in the Utica combo play. We now have over 6 months of production data from the first 2, the Timberwolf and Xavier, which continue to outperform our expectations. Daily production rates per well have averaged more than 1,000 barrels of oil NGLs and 4 million cubic feet of gas over the first 6 months. On average, these 7 wells have produced more than 200,000 barrels of oil per well since being brought online in the second half of 2023. We recently brought on our third package, the White Rhino.
Thanks, Keith. I would like to note the following important takeaways: First, our differentiated business model focused on exploration and innovation has built one of the deepest highest return and most diverse multi-basin portfolios of inventory in the industry. The Utica, our most recent exploration success will be competitive with the premier unconventional plays across North America; Second, consistent execution in our core Delaware Basin and Eagle Ford assets delivers outstanding operational performance quarter after quarter, while investment in our emerging plays contributes to EOG's financial performance today and lays the groundwork for years of future high-return investment; Third, our robust cash return to shareholders continues to demonstrate our confidence in the outlook and value of our business; Finally, one of EOG's best champions of utilizing innovation to constantly improve the company as our friend and colleague, Billy Helms. Billy recently announced that he will retire at the end of this month.
[Operator Instructions]. And our first question today comes from Steve Richardson with Evercore ISI.
Ezra, I was wondering if you could talk a little bit about the gas outlook, particularly as it regards Dorado. I appreciate that you're moderating activity in the near term. But maybe you could talk a little bit about if the forward curve, it sounds like you all are pretty bullish on demand and the forward curve certainly reflects that -- [ $3.50, $4 ] out on the curve.
Yes, Steve, that's a great question. This is Ezra. So you're right, gas, obviously, it's stating the obvious, but inventory levels are very high after 2 consecutive warm winters. But I will highlight in the last 2 years, we've also seen strong demand on the power side during the last 2 summers. And we expect that to obviously continue into this summer. So strong summer demand, coupled with the reduced supply, not only from some operators curtailing but just from the reduction in rig activity we see the potential inventory levels could come off quite a bit in the second half of the year.
Great. And so Ezra, would you, [ hastily ] guess. I appreciate that you've got this downside flexibility in a low price environment, but in a $3.50 or $4 price environment, could we see activity go to 2 to 3 rigs or don't want to get ahead of ourselves, but -- and I appreciate that there's probably efficiencies you want to retain on the upside as well.
Yes, Steve -- the last part you touched on is exactly the right way to think about it. It's the way that we think about it. We don't want to outrun our pace of learning. Now we are very constructive on the longer-term gas forecast for demand in North America. And we've talked about it before. We think Dorado is advantaged, not only with the cost of supply, but really with the geography where it's located, so we can service all the upcoming demand along the Gulf Coast.
And our next question comes from Arun Jayaram with JPMorgan Securities.
Ezra, you returned over 100% of your free cash flow this quarter, above your 70% target for the year. I was wondering what the signals to the market -- historically, you haven't returned this level of cash flow. So -- outside of the fact that you thought your stock call below $120 was dislocated, any other implications you think to the market from this -- from the buyback activity in the quarter?
Yes, Arun. This is Ezra. I'd say last year, we did return to the market through buybacks and specials and our regular dividend, about 86% of the cash flow. So having higher quarters is not out of line. The big difference, as you highlighted is that it was all biased towards buybacks rather than specials. And that's really been the trend over the last few quarters and I think that trend will probably continue.
Great. My follow-up, Ezra, based on the 2Q guide, you're spending around 56% of your full year CapEx in the first half. I was wondering how the timing of some of the strategic infrastructure spend you highlighted last quarter, how that's influencing the first half CapEx? And just thoughts on confidence in the hitting the $6.2 billion full year CapEx guide for 2024?
Yes, Arun, this is Jeff. Thanks for the question. What I'd first say is our 2024 plan, it's playing out as we had expected. So everything is in line as far as timing, and we still feel really confident with the total CapEx budget of $6.2 billion.
Our next question comes from Neil Mehta with Goldman Sachs.
I just love your perspective on the Eagle Ford and Bakken fields entered to more maturity. Some of your peers have talked on this earnings season about different things that they're doing to extend the life and deepen the inventory and just would love your perspective on some of the things you're doing on the ground to drive as much value as we get into the next phase of these assets.
Yes, Neil, this is Jeff again. With the Eagle Ford, we've got a really good, consistent program this year. We're going to be completing about 150 net wells there. And as far as looking at the well performance, everything has been in line and right with our expectations. With any mature asset, you're going to see some productivity degradation. I mean we started out in the East where we had a little bit more prolific geology. And then more recently, we've moved out to the West, where it's slightly lower quality pay, but the key takeaway is we've been able to continue to improve the economics in that play year-over-year. And we've really done that just through -- as you talked about, increasing operational efficiencies and focusing on drilling faster, completing faster with super zippers, longer laterals and cost reductions that have continued to improve the capital efficiency of the play.
And then Billy, I just want to extend my congratulations to you on your retirement and thanks for the insight over the years. My follow-up is just on the macro, on the oil macro specifically. We've got OPEC meeting coming up here in the next couple of weeks and a lot of uncertainty on both the demand and supply side. So -- just how is this year from a commodity perspective -- oil commodity perspective trended relative to your expectations? And I know you have a big in-house operation looking at the macro. What's the crystal ball telling you, Ezra?
Yes, Neil. Well, I'd start with the fact that Q1, I think, has really played out as most people expected. There is a bit of a pullback in demand there. And that's one thing that had prompted I think, had prompted some of the spare capacity being brought offline. But ultimately, that demand was about 102 million barrels a day. It looks to us and others out there, other models, it looks like demand should strengthen throughout the year. So we have not only seasonal demand picking up here, but also we're seeing underlying strength in the U.S. economy. Also in the China, the Chinese economy, just a little bit, namely on the manufacturing side.
Our next question comes from Neal Dingmann with Truist Securities.
My first question today, is on your Utica play, specifically looking at the map on Slide 12, it appears you all continue to target more so the eastern side of the volatile window, I'm just wondering. Could you talk about your thoughts maybe on the prospectivity of the black oil window? And if there's just anything that you might see this year that might cause you to change activity in the play for the remainder of the year?
Yes. This is Keith. You're right, we have been delineating mainly north south through the valid oil trend. It's a 140-mile area. The first thing we need to -- kind of on the west is we need to acquire seismic data. We're in the process of doing that. We need to see the degree of structural complexity kind of before we don't -- before we start developing. But geologically, in general, we don't see significant changes in thickness or pay from east to west. On the West, you're going to have a little bit lower maturity, which would equate to less pressure. But in our other plays, such as the Eagle Ford, less pressure reduces the well productivity, maybe a little bit, but it also reduces costs. So your economics are still really comparable to all the other portions of the play.
Very good details, Keith. And then just a second quickly on -- look at the supplement Slide 12, I like that slide you talked about just your marketing opportunity is. Statistically, I'm looking at sort of around the oil side, the U.S. oil. Is there opportunities to increase around the export side if opportunities present? Or maybe just talk about the optionality or flexibility you might have around those markets?
Yes, Neil, this is Lance. Yes, I think what we like best is just we are advantaged. When you think about just from the supply that we have out of the Delaware Basin, the capacity, the firm capacity that we have that can come into the Gulf Coast. And then the facility that we're down in the Eagle side, it's just -- it's an outstanding facility. They recently just increased the dredging that's there. So we're actually been loading [ DLCCs ] there. So the capability that we have there and our tank position, we've actually been pushing more across the dock into the export markets in the most recent quarter.
Our next question comes from Scott Hanold with RBC Capital Markets.
Yes, thanks. A little bit more on the Utica. I appreciate the fact that you guys do not want to outrun your learning curve. But given that. You're demonstrating some pretty good competitive economics with places like the Permian, just big picture, like what needs to happen and what do you need to see for this to be become a more meaningful part of your capital allocation and production going forward?
Scott, this is Ezra. Yes, I think we're very happy with where we're at. It's over a 400,000-acre position. As Keith highlighted, it's 140 miles north to south. And let's be honest, we've got 2 packages on right now. Now the 2 packages are fantastic. They're exceeding what we initially had in our type curves, and they're more than confirming some of our early thoughts on the spacing test. So at this point, everything is going in the right direction.
And before I ask my next question, I want to extend my congrats to Bill as well. Obviously, we all appreciated your insights and expertise over the years.
Scott, this is Jeff. Yes, just on the activity in Trinidad. We're currently just running our 1-rig program there and everything is going really smooth. Earlier this year, we completed 2 of our remaining wells there in the Modified U(a) Block successfully. And brought those online. And we're currently drilling and completing a couple of exploratory wells in the SECC block. And then after that, we'll move the rig and we've got a couple of recompletes to do in our Sercan area. And then one more exploration well to finish up the year in TSP area.
Yes, Scott, we've always been real pleased there in Trinidad, especially when we think about our price realizations and obviously meeting that local demand into the country. So I think you can see even with the price realizations that we had in their first quarter, they were very attractive. So we continue to see that kind of on a go-forward basis.
Our next question comes from Leo Mariani with RothamKM.
I wanted to just follow up a little bit more on the exploration side. Obviously, you guys seem happy where you are in the Utica. But just wanted to kind of ask in terms of activity levels. Is there other kind of ongoing exploration still this year in some of these U.S. oil stealth plays and perhaps you can just talk about kind of levels or wells? I know you're not going to reveal necessarily any of the specific areas.
Yes. Leo, this is Ezra. I'll start with the exploration and then hand the DD&A details over to Ann for an answer. On the exploration side, yes, we do have some exploration dollars in the budget this year, as we highlighted on the first quarter call. We continue to explore for -- yes, we continue to focus on oil plays. But at the core of it, what we continue to explore for things that are going to be additive to the quality of the corporate portfolio. And that's what you're seeing with the Utica, obviously. So that's a major success for us. We're not exploring for things that are simply just going to add inventory. We really want them to be additive on a returns basis, additive on a cost of reserves or refining and development cost basis, and that's how it contributes into lowering the DD&A rate.
The DD&A, you saw an increase in the first quarter was just due to a onetime prior period adjustment due to some natural gas production being used in our gathering systems. We did come in at guidance level, and you can't expect that DD&A to moderate over the remaining 3 quarters for the year, respecting about $10.50 for the remainder of the year.
And then I just wanted to follow up real quick. Obviously, you guys are pretty optimistic on natural gas kind of laid out some pretty big demand increases over the balance of the decade. You spoke a little bit about 2024, second half continuing to look better. Maybe if I just wanted to focus a little bit more near term. As you look at '25, strips kind of just north of [ $3.50 ] or so. Are you just increasingly bullish on '25? Do you think that strip price is pretty reasonable? Or do you think things can potentially be better than that? I think everyone is kind of on board that demand will be a lot better later this decade, but I just wanted to maybe focus a little bit more on kind of the next year or so.
Yes, Leo, this Ezra. I don't know if I'd call it bullish on '25, but I would say that we're constructive. As I said, we've seen a surprising upside on the amount of natural gas demand for power generation over the last couple of summers, and we continue to think that's going to be true this summer. That -- a big part of that is coupled with coal retirements.
The next question from Paul Cheng with Scotiabank.
Also I have to apologize, but I want to go back into Utica. If I'm looking at a well cost or that well productivity, what kind of improvement you need in order for you to move from the peso [indiscernible] to the -- or delineation [indiscernible] of the manufacturing or production development now?
Yes. Paul, this Keith. So I'll start on the well cost. It's still early on the play that team continues to drive down the cost. We see a lot of room for further efficiencies, the consistent activity this year with 1 full rig has helped that a lot. We like that generally in the area, it's an easier operating environment compared to a lot of our other plays. That's consistent geology. It's a little bit shallower depths. Example of that is our 3.7 mile lateral we just drilled on the [indiscernible].
I see. Before I ask my second question, I also want to add my congratulations and best wishes to Billy, thank you for the help over the past several years.
Yes, Paul, this Ezra. Yes, the $400 million of infrastructure, the strategic infrastructure that we've highlighted before, which we couldn't be more excited about because of some of the long-term margin expansion benefits that Jeff highlighted it in the opening remarks. These are projects that, historically, we look for opportunities like this, but they're very rare to present themselves where we can take on infrastructure projects that generate such a compelling rate of return. We've talked about the Verde pipeline is expected to generate about a 20% rate of return uplift. And then on top of that, we get that GP&T savings, a netback uplift of $0.50 to $0.60 per Mcf over the life of the asset.
Our next question comes from Derrick Whitfield with Stifel.
Leading on the Utica, it sounds like the southern part of the trend could be advantaged on returns based on the elevated NRIs and potential geology. Could you perhaps expand on the difference you're seeing in the geology between the north and the south?
Yes. This Keith. So yes, it's still early in the play. We're learning more every day about how the geology ties to production. It's going to obviously vary over the 435,000 net acres. But in general, the Utica is thicker in the North. The South is a little bit better pay, but it has better geomechanics and rock properties. That has to do with frac barriers and keeping the frac energy more contained near the wellbore.
Great. Then bigger picture question on the PRB Niobrara. Assuming further D&C optimization efficiencies based on your progress to date, could this play compete with the Delaware and Eagle Ford over time in returns?
Yes, Derrick, this Jeff. So yes, we've made a lot of really good strides there in the PRB. We started out really focusing in on that deeper Mowry really to refine our geologic models kind of throughout the whole section. And we had good success with the Mowry with that. We went into package development last year, and we saw with package development, a really good uptick in overall productivity there, about 10% in Mowry. So once we accumulate enough data, we went ahead and we're moving up in section in the package development there in the Niobrara. and just really started drilling some wells this year, having really good success operationally, and we'll look to be bringing some of those on later in the year here.
The next question from Nitin Kumar with Mizuho Securities.
Congrats to Bill on the retirement. Thanks for all the help over the years.
Yes. This Jeff. We obviously keep our finger on kind of what's happening with refracs and that technology out there. We've done tests in the past in multiple basins. And what we really find is just with our robust inventory across our multi-basin portfolio. The opportunity for refracs, we're much better to either go in and offset an existing completion that was maybe poor or lesser or just go ahead and drill a new well in a new section from that aspect.
Great. And I guess as a follow-up, we've talked a lot about gas macro today, but you have a pretty strong marketing arm. Are you starting to see demand pull directly from the producer from some of the AI or Mexican exports or any of these kind of tailwinds to gas macro demand that you're hearing about?
This Lance. Yes, I mean, it's still pretty early on the AI front. But I'd say when you think about us, you're right. I mean we do have a lot of capability and a lot of reach with the marketing arm. We are very pleased with the execution that we have. We talked a lot -- you heard even Ezra talk about the pillars that we have there with diversification and control the flexibility. All those things provide the reach that we need as we think about our price realizations [ sync ] into the most attractive markets.
And our final question comes from David Deckelbaum with TD Cowen.
I just wanted to ask a follow-up just on the Utica, particularly as you fit into some of the analogs and other plays that you've been in, in the life cycle of that exploration and development program. How do you think about testing longer laterals in the Utica specifically over time? Which seems to be a play that's quite amenable to even lateral lengths beyond 3 milers versus attempting to get down your footage cost? Sort of where are we in the theoretical innings there?
Yes, David, this Jeff. We're in the very early innings there. And what I'll say operationally is the Utica sets up, I mean, almost perfectly. It's the efficiency gains that we're able to see there, we're getting better with just about every well. And as Keith had talked about in his opening statements, we drilled our longest lateral there to date at 3.7 miles. Our program right now consistently is 3 miles, and the team plans on continuing to push that out just because we can do one runs in the laterals and stay on bottom longer and not have to trip out of the hole, and we really have no problems operationally completing the wells.
Appreciate that. And just my final question. Just as you think about the incremental few hundred million spent this year on strategic infrastructure, and some other projects along the infrastructure side. How do you think about sort of the forward capital intensity of infrastructure as you continue developing in the '25 and '26 and beyond? Is that a number that should increase with intensity every year just given some of the infrastructure calls that are out there currently? Or is this sort of what you feel is like a steady run rate as a percentage basis?
Yes, David, this is Ezra. Those are fixed projects, the strategic infrastructure that we're talking about. And so the best kind of way to look at it, maybe is to reference that 3-year scenario that we have out there. Now that is not guidance, but it is a scenario that potentially assumes a similar macro environment to what we've seen in the last few years. And what we could do going forward.
Thank you. This concludes the question session. I would like to turn the call over to Ezra Yacob.
Thank you. We appreciate everyone's time today. I'd like to hand the call over to Billy to wrap up.
Thank you, Ezra, and thanks to all of you for your kind remarks, and I truly have enjoyed the chance to meet all of you and work with you in the past. Let me just add, I've been blessed to be part of this company, and its unique culture for the past 43 years.
Thank you. The conference has now concluded. Thank you for attending today's presentation.