Welcome to day two of the Barclays 40th Annual Energy and Power Conference. We have a full pack schedule in the E&P track for the rest of the day. A lot of great conversation to look forward to. Kicking off the E&P track today is EOG Resources, Jeff Leitzell, COO. Really looking forward to the conversation to start. Jeff, why don't you join me on stage? As we've been doing with the conference, we're starting with an audience polling question, so let's do two quick ones to start. At what oil price do you expect to see a meaningful increase in U.S. shale activity? $70-$ 80, $80-$ 90, $90-$ 100, and more than $100. We're seeing more increasing private activities. All right. $90-$ 100. I think that's pretty fair. We're seeing more from privates, but certainly not from publics. Next one. What do you see as the most attractive new frontier development area? Argentina, Canada, Middle East, conventional and unconventional, or other. Argentina and unconventional and Canada. All right, well, at least I picked the right ones to go on that multiple choice. Thank you very much for participating. Jeff, thank you so much for being here and having this conversation. I want to kick off with exploration. Sure. I think you guys have been talking about exploration and maintaining that expertise for a while. I think the market is really catching up to it and growing enthusiasm around what you're doing, both in U.S. onshore and international in U.A.E. as well. Before we go to U.A.E., I want to ask about how EOG's capabilities internally able to set up the company to identify these opportunities early, and what characteristics around these opportunities that makes them worthwhile for EOG to pursue? Yeah, that's a great question. Exploration is near and dear to our heart. It's obviously a big part of the company. It's a core competency. Really, we like to tell people it's part of the actual company's DNA. So, one of the things that we've always done since the inception of the company is we've really honed that skill set. It's something we've tried to hold onto and as we have new generations come in, we try to pass down that information to them so we have future explorers to continue that skill set. The other thing is our decentralized structure really helps that out because we have seven domestic divisions. We have a division in the GCC now, we have one in Trinidad, and then we have an international division in Eastern. Each one of those are exploring in their area, so they can really put a lot of focus and intention on finding what the next resource is in that area. We've got a very structured way that we look at exploration. What we're trying to do is really look for four primary characteristics and at least check three of the boxes. The first one would be scale. It's got to have enough size. You want to have high rate of return. You want to have low or potential for low F&D, and then you also want shallow decline if possible. Those are really the things we look for. In order to really gauge those things, you have to have some data. So we go into areas, it's nice if there are obviously some penetration points. Maybe there's some geologic data, older vertical data, maybe some older cores, older logs, seismic that we can work on. Maybe there's a little bit of vertical production that we can go ahead and we can extrapolate out to what might happen in a horizontal. We like to see, if possible, maybe there's a little bit of services in the area that we can utilize. Also infrastructure. If you have some infrastructure in the area, you can really keep your all-ins in the front of the actual play down, so it really makes the full cycle economics that much better. I think a couple great examples of what we've recently done, obviously people know about the Utica organically exploring and finding that and then making the Encino acquisition. But even if, we've found that it doesn't necessarily have to be a greenfield entry. We've seen bypass pay step-out areas and extensions just with technology that you're able to explore for. A couple good examples of that would be the latest Austin Chalk sweet spot that we talked about there in the Eagle Ford. Just southeast of our Eagle Ford primary, we could use that geologic data and reservoir data to find that. Also, as we've talked about our entry into the GCC, we see a lot of opportunity in international unconventionals. Obviously our entry into Bahrain, which is an unconventional gas play, and then the U.A.E., which we're excited about, which is a pure oil play over there with 900,000 acres. Before we talk about U.A.E., how is the opportunity set that is out there in the world today different than what it used to be? We are hearing more and more about governments looking for partnership or opening resource access. Do you think the opportunity set has also improved? I think it is getting better, yes, absolutely. I would say the first thing is we see people think that there is inventory degradation and there is no more place to find domestically. We do not believe that. We still see a lot of opportunity for exploration and to be able to find very economic resource here in the U.S. Yes, as you look internationally, there has been very little unconventional international operations. Obviously some in Argentina, there has been some up in Canada, but there is unconventional rock all around the world. It is really just about having some of those boxes checked that I talked about as far as characteristics and hopefully having a little bit of data to get into them. We have seen an evolution with a lot of the different governments out there, where they are becoming much more knowledgeable and understanding, not just how conventional operations and financials work, but also unconventional financials. We have been able to see, we can get in and we can actually partner with some of these entities and get a piece of the actual resource and be able to go in with our technology to exploit it, but then also partner with them to where they can learn off of us from our unconventional technology. Right. Talking about learning from your unconventional technology, your view is really to transport or export a lot of your capabilities in U.S. unconventional to international, to U.A.E. What gives you the confidence that this can translate, given region is different, equipment might be different. What gives you the confidence that what you do in the U.S. can be applied internationally? Yeah. I'd say, the easiest thing to point to is the actual success we've had out the gates over there. We knew there was going to potentially be some challenges, but we've been extremely happy with what's happened over there in the U.A.E. What that is it's a 900,000 acre, first of its kind unconventional concession there in the U.A.E. We've went in, we've started our exploration program. We have a three-year exploration phase on it. We've drilled our first handful of wells. What I'd say is operationally, we're very happy with what we're seeing there. We're able to apply some of the technologies out the gates, not all of them, but at least initially to be able to look at the reservoirs. We brought on our first two wells, and they were just 1 mi laterals. Not necessarily optimal casing designs or optimal completions, but really just to test the formation. Those wells, they produced each 25,000 bbl of oil in the first 30 days. With a caveat to that, I'll say is, we had about a week or so that we were having to optimize facilities within that. It's the first time that you're stepping in and you're learning about it. There's still a lot of upside that you can bring to it. Both of the wells were flowing natural with no artificial lift. What we've seen is, we see great pressure profiles on them. The fluid mix is matching exactly what we thought. Everything's really encouraging. I think the exciting thing is we see so much upside with this. There's a lot of improvements that we can continue to make by applying that unconventional technology. What we're planning on doing now is we're going to move forward. We're going to drill some longer laterals, 2+ mi because we've seen the success from the drilling activity and then continue to hone in. We'll work on understanding exactly what's the best target, potentially what's the best spacing. We'll delineate the 900,000 acres to really understand what we have there, confirm the fluid mixes. We'll hopefully move towards a declaration of commerciality with success in all that. But extremely excited about the opportunity over there in the U.A.E. Right. I was going to ask, what characteristics do you want to de-risk before you get to development plan? You just gave me a list on the operational side, on the rock side. Is there anything else on the infrastructure side or on the commercial side that you need to de-risk as well? No. I think everything previous to making the agreement with ADNOC, we had checked a lot of those boxes to make sure that we would have adequate takeaway throughout the life of the play and be able to have that infrastructure in place in a timely manner. Really what I would say is, we've been asked that multiple times, what are the challenges and what are the hurdles we see? I think if anything, we see a lot of low-hanging fruit is where we're at. I would also say ADNOC's been an absolute amazing partner so far out the gates. It's really been a hand-in-hand relationship there. Complete transparency, sharing, and they've really been willing to work with us and help us remove roadblocks to continue to make that asset better. Some of the things that we're allowed to do too is, we can bring that technology over, and they know that's very important. We have EOG Motors over there on site right now drilling the wells, and actually we've just started in-basin sand mining in the dunes, which normally they're transporting in sand in super sacks and from many, many miles away. We see all this very, very high quality sand right there. So we were able to permit, and we're actually working with them to show them how to mine sand right there, and it really minimizes the cost and the transportation. Great. Well, bringing it back home to the Delaware, EOG has continued to find zones and improve the overall recovery of the asset. Where do you think we are in the inning of that asset now? Is it fairly optimized at this point between return, maximizing NPV at a section level versus return on the individual well level? Yeah, I'd say, the Permian is the gift that keeps on giving. We keep finding ways, whether it's through technology and our development approach, as we lower costs, that we're able to bring forward more and more value there. Now, you are correct. It really is a balance of maximizing the total resource extraction with optimizing those economics. That's something that we've had to work our way through, as you know. The one thing that we really base ourselves around and underpin everything on as we start, our 1A is going to be returns. We've got our stringent threshold of a 30% direct after-tax rate of return at $45 WTI and 250 Henry Hub gas. As long as you meet that threshold, you can actually get investment. You have to actually hit that minimum criteria. Once you hit that minimum criteria, you have to continue to optimize economics. What we look at is we try to optimize the payout on a well basis. We would like to have at least probably a payout of less than a year by a well basis. We want to have the ability to obviously drive costs down, improve performance to where you can lower that F&D cost, which obviously flows through to your DD&A rate, and it really helps for margin expansion from that aspect. I think that is one thing, as technology continues to evolve, that is pushing the limits out there in the Permian. Not only that, obviously we drove down our costs over the last handful of years, we talked about 20%. Last year, we brought in numerous new, unique targets that meet that threshold and that rate of return. You are constantly evolving your development approach. You are working on your completions designs, your spacing, you are looking at different targets. I would never count the Permian out. I think there is still a lot of value as far as different potential targets within the stacked pay, and then also extensions in the step-out areas. What I would say is, with our Permian acreage, because of this technology and how it has moved forward, and being able to really maximize that NPV per acre, that is why we have got such a robust inventory there. We have got 10 years plus of total inventory still in the Permian at our current paces. It is going to have very similar economics and financials to what we have today. Shifting to the Utica, that is your newest foundational asset in the U.S. You are gathering more and more data. There is more development on that asset. Is there new things that you are finding, operational advantages or new data that is influencing how you think about the development of that play going forward? Yeah, it has been a great progression there. I say, out the gates, we have not had a miss in the Utica, all the way from exploration to delineation. It really has to go back to understanding the rock. What really makes the Utica work, which many have looked for it and tested it over the years, is you have to understand depositionally where you are actually at throughout the play. If you look at the play and you start over to the east and you are over near Pennsylvania, you are deep in the basin, so you are in very mature gas. As you start to move into Ohio, you start moving up dip, you get into a condensate window, and then a volatile oil window, and then up into an actual black oil window as you continue to shallow up in the section. What we found was that volatile oil window is really the key point. You get to a point where you still have enough depth and pressure to really get good production rates, and you also get enough associated gas along with that oil to help really energize and lift the well throughout its life. That really seems to be one of the better productive areas. So that is really where we are focused on at this point. Then as we got into continued delineation, we noticed there are differences within the rock as you move from north to south. In the north, you tend to have maybe a little thicker section without an actual frack barrier. It is very conducive to maybe stacks or staggers up there, and you can have a little bit tighter spacing because you do not have that barrier that you will frack into and then frack out. Down in the south is a little different. We have a very robust frack barrier down there. So your spacing, you might have to space out just a little bit wider because you tend to frack up and actually hit that barrier there. Just through our success here in the first handful of years, it has really given us the confidence to move forward to actually make the Encino acquisition, which we did last year, below mid-cycle pricing, which is normally what our target would be for an acquisition like that. We were able to increase that volatile oil window by over double to 485,000 acres. Also on top of it, we got about 300,000 of premium gas acreage. Which we are not focused on the gas window, we really are focused on that volatile oil, but we did acquire a DUC package in there and went in. It was 3.5 mi wells, three-well package. We just wanted to see what the performance was, and each one of the wells came on at 35+ million a day. So very prolific gas that came along with it. Then, from an operational front, we have just had huge success, especially with the combined company between Encino and us. On the drilling side, we have been able to reduce our feet per day drilled by 23%. On the completion side, we have been able to increase the feet per day, I should say, for both of those by 12%. We have been able with our supply chain, we have a robust supply chain, the group that has really worked hard, and I think we have dropped our casing and tubular cost by about 30% there. Then on the facility side, just with doing much more centralized facilities and bringing our knowledge to that, we have reduced it by about 20%. So when you roll all that up combined between the two companies, we are well below $600/ft. I think the exciting thing is we still have a long way to go because we actually are partnering with a third party, and we are going to be opening the first in-basin sand mine in Ohio. It is right in the center of our field, prolific reserves for the life of our play, and it is really going to minimize transportation and the overall cost of getting sand to our location. Is that already accounted for in the $600? No, that is all icing on the cake. The actual sand plant will be up and running, we hope, by the end of the year. That will all just be extra potential savings that we can see. I think it is one distinction that Utica is a liquids play for EOG that comes with a gas optionality, and you explore that optionality with the gas pad. But the real gas asset is Dorado- Yeah. ...sitting in South Texas. You pulled activity back a bit this year, given the lower gas price environment, but it still serves as a strategic gas asset. How does the gas strategy fit in to EOG's portfolio? There is certainly a lot of talks about data centers and adding more gas power plants in Texas. Just how do you exercise the gas assets in the portfolio? Yeah, I think, Dorado, it was very strategic from the get-go. We knew gas was going to be a big part of the future. We wanted to look for prolific resource that was very close to the coast, and that is exactly what we found. It was close to the market center. We have almost 20 Tcf of gas there. Really what we have done is we have kind of stood up a whole separate gas company next to our actual oil company. We think it is the cheapest gas in the U.S., low cost at about $1.40 break-even price. The wells come on very strong, as we talked about. We keep them very choked back at kind of 20 million- 25 million a day. It is prolific. You can bring on a lot of volumes very quickly. When we saw the early success in it, we knew we were going to have a large resource down there, and we are going to need a way to get it to market. We actually went out to market and asked third parties what it would cost to put the infrastructure in. Did not like what we were seeing for fees and stuff coming back. We decided to go ahead and be opportunistic and lean in and build out the pipeline down there. We actually fully own, it is all EOG's capacity, a 100 mi, 36 in pipeline that goes from basically the center of the field over to Agua Dulce, which is the market center, and it has a 1 Bcf base capacity. Which, as I said, is all EOG's. It is easily expandable up to about 1.7 Bcf a day, just with some booster compression that take us very minimal time to set and put it in place. We are extremely excited about it. Then we can actually tie it in with all of our great marketing and the marketing strategy that we have had about diversification and flexibility there on the coast. We have got our LNG agreements where we have got close to a Bcf of offtake over there. All of our Cheniere agreements are on, which includes 420,000 MMBtu, which is monthly election, either JKM or Henry Hub linked. We can elect that on a monthly basis. Also, we have got 300,000 MMBtu a day that is linked directly to Henry Hub without any differentials. Then looking for more market exposure on the international front, we actually recently did a deal with Vitol for 140,000 MMBtu, which is Brent linked, which helps take some of the volatility out and get more of that international link pricing. That comes along with, I think, 40,000 a day Houston Ship Channel. Then on top of that, we also took out about 360 million a day on Transco's TLIP line, which actually runs all the way around the coast over to the southeast market center, which is where you really have premium. Yeah, we can flex Dorado very quickly in response to the market whenever gas is needed. Obviously, we will keep an eye on the gas market as LNG continues to pick up there on the coast. Also, as you talked about, the opportunity for additional power demand in data centers as that continues to evolve with time. Yeah. I think the commercial strategy is worth highlighting because being able to think ahead of the time, ahead of the market, and get these agreements in early, really extracts value long term. Are there things that opportunities in the market that on the commercialization, on the marketing side that is interesting or as we think ahead for the next 5+ years? Yeah. I think there is still a lot of opportunities to get international pricing on the LNG side. Our initial Cheniere agreement was very unique. It is tough to get another agreement like that, but we are getting creative. We are trying to link it to different international markets to make sure we have a premium, and it gives us lots of flexibility. Also, as you talked about here domestically, there is a lot of interest from the data center side. I think it is just a matter of it maturing a little bit more in that market and getting to a point where we would like a premium price, obviously, for our gas. I think a lot of the data centers, they would like cheap, reliable gas. So finding the right price in the middle that makes the right choice for the company. I think really you can kind of look at some of those deals almost as like a hedge if you were to do it. So I think it is strategic, and they work in areas where you have stranded gas and there is potential opportunity, like I said, as that market evolves. That makes sense. Technology. EOG has always been the technology leader. In my seat, I just find we're in this technology renaissance that they're seeing new, different ideas and innovation that's making the assets better. Where are you seeing the most change or competitive advantage where the technologies bring to the EOG's assets? Yeah, technology is constantly evolving. I think we look at it from a multifaceted lens, because we're constantly innovating, trying different things. I'd probably break it down into three categories for EOG. The first is well performance, or really what we want to talk about is recovery factor, because that's what the holy grail is. One of the things that we've done, I think, that's unique is we're really focused on what we call our ultra-high-intensity completions, which they're unique from a multitude of angles. The first thing is, each well and well bore we design specifically for what treatment we need to really maximize the overall productivity of it. What we've also done is with our actual frack fleets, the majority of our frack fleets can do 200 bbl, 240 bbl a minute. We have a lot of energy that we're able to apply down hole. The main focus there is to be able to uniformly distribute that energy along the rock within a stage to maximize your overall surface area. Ultimately there, by introducing and creating as much fracture face that you can contact with the well bore, that's what you're creating really there is that connectivity to the well bore that increases your overall recovery factor and your performance. We've had a lot of success. We've talked about the success we've had over the last five-plus years in the Permian, and we continue to test new iterations of that. Most recently, down in Dorado, where just last year alone, we've had upwards of 15%-20% increase in productivity by applying those high-intensity completions. I still see a long way to go there. Like I said, we're designing specific well bores now to really remove any kind of limits or restrictions we have, and we're really seeing a lot of great progress with that technology. The second I would say, would be probably cost and efficiency side. One of the big things we always talk about, but we're only really at 30% utilization in the company, is the EOG motor program. It's something where we stepped into the market. We tried to partner with some drilling motor companies. What we saw was we wanted to push the motors to the limit, find out what would break, and then redesign them to where we could understand on the metallurgy, on the connections, on the components, what needed to get better so we could basically create the indestructible motor. It was tough to partner with anybody, so we said, "I guess we're getting into the motor business," and it's just been a home run. We've seen great success all across the portfolio. I'd say probably the greatest success to point to is even in Dorado. It's our toughest drilling. It's high pressure. It's high temperature drilling down there. The majority of the wells that we actually drill, we can actually drill the vertical, the curve, and the lateral all the way out multiple miles with one BHA. Those are mostly all EOG motors. That's one of the technologies that I think we're really pushing, has a lot of upside. Another, I would say, is continuous pumping. We're to the point we don't even shut down on frack jobs. We basically will go ahead, lower our rate down to about 10 bbl a minute. We have auto valve systems that close the wells around, open the new wells, and automatically redirect the rate, and you go ahead and ramp your rate back up. There's really no downtime whatsoever in between stages. We've also seen it has a huge effect on the maintenance side of it. We've actually created barriers with inside of our fleets, so you don't have to pull them out of line to work on them. You can basically take it offline, remove it from the pressure, but you don't have to move that pump, and you can continue pumping with the rest of it. A lot of great stuff going on that. The last one I would say that's hitting a lot of the industry and the world is data analytics. We have really two areas, I would say. Sensors and in the AI realm. In the sensor realm, what we've done is we've started putting a lot of sensors down hole to where we're able to capture very valuable geologic data. Things like Poisson's ratio and Young's modulus, understanding where fractures are within the rock, and we can get that data and obviously apply it as we continue to drill the well into our completions and onto the next wells on. We've also taken those sensors, and we've placed them on all sorts of surface equipment. So we're constantly listening. We're recording the vibrations in it. If you see any kind of change in the harmonics, you can identify failures of all sorts of equipment before it actually fails, so you can minimize the damage to it. You can quickly shut it down, fix it, and you don't have major downtime events. That's been very, very big for the company, and we've really been rolling that out heavily over the last couple of years. The last one is AI. What I'd say is it's becoming a big part of our business, as it is with everybody's daily life. What I would say is this, it's not going to replace our people. Our people are truly our resource, and they're the innovators out there to push the limits on what's going to be next in the industry. It's taken those monotonous tasks, whether it's documentation, reporting, whether it's the analytical side of it, whether it's even just software engineering and programming. It can take those monotonous tasks off, do them very quickly, and allow our people on really focusing on innovation and adding more value for the company. I'm hearing better wells, lower cost, and more efficient organization. We are hearing more about inflation commentaries here at the conference, particularly from services. Does that basically offset everything you were saying on the technology and efficiency side, basically can offset the inflation? Or where do you think the cost trend, net of everything, is trending? Yeah, I'd say, on the services side and the cost side, there has been some slight inflation, but we really haven't seen a huge shift. We've got very strategic partners. We're one of those people where we don't gouge them for the lowest cost whenever it's a downturn, and they don't gouge us for the highest cost whenever it's an upturn. I think that's one thing. The other thing is we're very insulated from the market. Diesel's been something that there's been huge inflation in across the board, and we're going to continue to have higher diesel costs. The majority of all our field operations run off natural gas. 70%+ of our rigs run off natural gas, and 100% of our completion fleets run off natural gas. That's been a great insulator. The other thing I think we got to keep an eye on is steel has started to increase across the market. We've leveraged our inventory where we normally keep a 6- 12 month inventory wherever it is, so we can opportunistically purchase ahead of time and really try to insulate ourselves from that. We've already started purchasing well into 2027 to try to insulate ourselves. Yes, I think it's a multitude of things. You've got to be more efficient, utilize the technology, continue to drive your cost down those ways, but you also need to insulate yourself from the market by doing a lot of self-sourcing and making sure that you're going out and you're procuring the things that you need ahead of time at the right price. Right. Well, unfortunately, we're out of time. Jeff, thank you so much for this conversation. There's a lot going on with the portfolio, so thank you. Yeah. Thank you so much.