All right, good afternoon and welcome to day one of our ninth annual Energy Conference. Excited to have EOG Resources to kick off our E&P presentations from day one. Joining us today is EOG Resources' EVP and COO, Jeff Leitzell, who's been one of the pioneers in the shale industry with a strong track record of operational execution and returns. Jeff has had various roles in the company and was recently named COO in December. So he's been all around the organization. Really, really excited to have Jeff to participate in the fireside chat with me this afternoon. Jeff, how are you?
Yeah, I'm doing good. Glad to be here, Arun.
Great. Well, Jeff, any investment in E&P involves understanding the macro picture because at the end of the day, you're a price taker, right? At the end of the day. I just wondered if you could highlight maybe the macro picture because I know EOG's fundamentals team does a lot of great work in terms of both commodities.
Yeah, so there's obviously been a lot of volatility here in the near or over the past years, and it feels like a lot of that's worked out of the system. And we really have a real good feel of where spare capacity's at right now. And with the OPEC+ cuts that are out there, it feels like the market's fairly balanced at this point in time. And what we really see is pretty strong demand around the world and continued growth. So we think that OPEC will probably start bringing some of those barrels back on outside of the voluntary barrels, maybe towards the back end of this year or even into next year. So I think everything's looking very, very good and bullish from the oil side. And we're really excited about the future from that aspect.
If you move over and you look at the gas side, now obviously that's a little bit more interesting. When we look at the beginning of the year, we kind of started going through the first quarter, we saw a pretty big drop off in prices. We had $1.60, $1.70, and so much that we actually kind of used the flex of our multi-basin portfolio and we pulled back some of our gas production down there in the Dorado asset to defer a handful of completions to the back end of the year. Obviously that's worked out. We've seen prices kind of peak up here a little bit. Really what we want to watch now is, I mean, we still have pretty high storage levels.
So we'll see kind of what type of summer we have from a weather standpoint and then moving into winter, what kind of power demand draw we have from there. And then looking forward into 2025, we're obviously really excited because we're going to start seeing quite a bit more LNG come online. So right now there's about 14 BCF of feed gas that's going offshore and being exported. There's another 10-12 that's being built out right now that's going to be coming on over the next three years or so. And we really think that's going to be a great opportunity. It's going to be kind of a pressure relief valve here for Henry Hub and some of the domestic prices.
We're really excited about our portfolio with that because we've kind of stood up a separate gas business with our Dorado asset down there in South Texas, which is really close to the market center with quite a bit of an LNG offtake there.
Great. I want to shift gears a little bit and talk a little bit about organic exploration opportunities. More recently, EOG has highlighted entry in three emerging plays, Dorado, the Powder River Basin in Utica. Let me start with just questions outside of North America or the U.S. How do you think about exploration opportunities outside of US shale?
You know, exploration is one of our kind of core values. I mean, it's one of the things we focus on both domestically and internationally. So with the international front, we have a lot of excitement there because one thing that we've seen is in our expertise, we really focus more on shallow offshore like our Trinidad assets and then also onshore unconventional, which we really haven't seen a lot of the different countries utilize the technologies and exploit it. So we feel that there's obviously going to be a lot of opportunities out there. But with any of our exploration plays, we look at it through a returns focus lens. It's got to compete with our portfolio. And on top of that, there's really it needs to mark three boxes of four.
So it needs to have basically a scale, so enough size to be able to get into it. It's got to have shallow decline. It's got to have a high return or it's got to have a low F&D cost. And those are really, if you can mark three of those boxes and you put together multiple plays within your portfolio, it really builds up to kind of one perfect play is how we look at it. So we're extremely excited. We think there's going to be a lot of opportunity internationally. We have an international group in our headquarters that's constantly exploring. And I think they've got a prospect list that is about as robust as we've ever seen. And the same thing goes for our domestic. We're always exploring for five to 10 different prospects.
We think there's a lot of upside and a lot of bypassed opportunity here in the U.S.
We have some Canadian companies presenting at the conference. How would you think about the unconventional opportunity north of the border in the U.S. or Canada?
You know, we had some Canadian operations in actually in more of the gas type areas. And really we found that it didn't compete. It was kind of a little bit tougher area to operate from that aspect. So we went ahead and divested those assets. And really what I'd say is we're looking everywhere around the world right now for any opportunity, but it does have to compete with the domestic portfolio. And what we've really seen is from just the overall cost structure, how services and other things work in Canada can be tough to actually compete with the domestic portfolio.
Makes sense. Let me shift gears and talk about the U.S. On the first Q call, Ezra talked about promising early tests from the stealth play. I don't expect you to give us more details, but give us a sense of where some of the testing and evaluation work is domestically.
So normally we don't really pull back the curtain until we actually get to a point of appraisal. You know that, Arun.
Yes, of course.
As I said, we have multiple prospects around the U.S. right now that we're currently, they're either in the prospect phase where we're just appraising it from a technical aspect and you really don't have to put a lot of dollars into it, or there's obviously a handful that we are allocating small amounts of capital for exploration. And really the goal is what we're looking for is new greenfield opportunities. And we're also looking for bypassed opportunities. The interesting point is, I mean, if you look at the U.S., I mean, we understand all the basins. They've been drilled through. We understand stratigraphically and the reservoirs that are there. But the thing is, a lot of them were drilled through 10 or 15 years ago, maybe 20 or 30 years ago.
Technology has evolved so much that you can go in and you can drill horizontal wells in these and exploit that technology. You can get just absolutely outstanding returns. So as I said, domestically, we're in an absolute great place. I think it's probably the most robust prospect portfolio we've had in the history of the company.
Okay. Next question is EOG has always taken kind of a low-cost approach to portfolio renewal compared to many of your peers who've participated in large-scale M&A. Jeff, nearly every one of your larger cap peers, Apache, Conoco, Chevron, Diamondback, Oxy have completed or are trying to complete large-scale M&A. And you think about Exxon as well into that bucket. Clearly, investors seem to be a little bit worried about your overall inventory depth. And have you missed the boat in terms of pursuing some of these inorganic opportunities? How would you respond to that?
Yeah, I think we're right on track. We couldn't be any happier with where our inventory is at right now. We have over 10 billion BOE of resource right now that's premium, which if you look at the premium metric, we have a pretty high hurdle rate for us to invest. It's going to be a 30% after-tax direct rate of return at $40 oil or $2.50 gas from that aspect. So we have an absolute amazing inventory right now. Then on top of that is really we like to lean in on more from the exploration front. So obviously the Utica, we'll use that for example. We were able to put together 435,000 acres at an average of $600 an acre.
And when you look at that and you compare it, we actually just talked about during our last earnings call, the initial well results that we see there compete pretty much with any basin around the country, including the Permian, which is extremely exciting. So that low-cost entry right there, I mean, what we see with some of the current M&A that's taking place is you pay an extremely high rate on a per-acre basis, which that immediately goes in and it will hit your DD&A. And it really makes it tough for margin expansion throughout the life of the play. Secondly, you tend to buy a lot of PDP, which PDP is great, but you're paying a market value for it. And what EOG really likes to do is use our technology to extract the value through drilling wells.
And then on top of that, you can have other issues where a lot of the acreage that you evaluate, it looks like yellow on the map, but it's non-op. And one of the things we really want to do is make sure we've got control of the acreage so we can exploit it and really maximize that value there. So I just think that right now we will continue to look at both M&A acquisition opportunities and organic growth opportunities. But the big thing is it's got to meet our returns hurdles. And that's really the lens that we look at it through is from a returns basis. And we're not just looking for acres that can add to our portfolio. We really want to have acres that are at the top end of our portfolio.
All right. The last question on this topic is just Trinidad. I believe you're in talks with BP to develop the Coconut Natural Gas Field offshore Trinidad. Can you provide more details on this joint development and just your broader opportunity set offshore Trinidad?
Yeah, Trinidad, we've been developing down there for over 30 years. We've got a great skill set there in the shallow offshore. And what we found is there's really just not a lot of competition in the shallow water. A lot of the operators down there, they're focused in the deep water portion. And what we found is we've got kind of a niche skill set there. We're able to do it very low cost on shallow offshore. And we're able to do it at very quick cycle time. So we've kind of become a preferred partner down there with a lot of different individuals. So we see in the future, I mean, there's still a lot of new leasing opportunities out of Trinidad. And then also there's a lot of JV opportunities with some of these operators you said.
We're able to go ahead and, yes, it's mostly gas down there, but we're selling it directly to the government, obviously for very advantaged prices there in the island of Trinidad.
Great. The next topic I want to ask you about is just cash return. Maybe you could start with the company's shareholder return framework and the return of capital that you've promised to shareholders.
Sure. Well, where it's at right now is we basically have a commitment for a minimum of 70% of our free cash flow that we generate a year. And that is a minimum. So I'll use it as an example. Last year we returned 85%. So really how we do that is the first thing is through a growing and sustainable dividend over time. And one of the things I think we're most proud of is we've had either a flat or a growing dividend for 26 years. And currently right now our dividend is $3.64, which is an extremely competitive yield within the S&P. And if you look at it over a five-year period, we've actually increased it 350%. So really outstanding performance. We think that we have that in great shape. And just with the health of the company, we'll be able to continue that pace.
Next, you move into the next returns, which is really going to be opportunistic share repurchases and then special dividends. Early on through our framework, we really kind of leaned in a little bit more on the special dividends. But more recently we've switched over and we've started buying back more of our shares. Over the last five quarters, actually, we bought back shares. Most recently here in the first quarter, we bought back $750 million of shares at $118 a share. So what we really see is just kind of a dislocation really between the energy sector and the rest of industry and really what our percentage in the S&P is. Then also just what we see is the forward upside and the potential of the company with just our exploration.
As I said, just how strong our overall portfolio is right now, it just made sense to go ahead and lean more into the share buybacks. I think going forward, you can really see that we're going to take advantage of any volatility in the market to continue to lean in on those buybacks.
Okay. Let's shift gears to talk about the portfolio. Your plan today is to run 27 rigs and eight frac crews, which are both lower on a year-over-year basis. Maybe start with kind of some of the drilling and completion efficiencies that you're delivering in the field on a year-over-year basis. What's changed there?
Yeah, the teams are just doing an outstanding job. And I mean, that's core to our culture right there, is constant improvement every single day and to get better with every single step that you take. So yeah, what we saw is if you look at 2023, we had an improvement of 15% in overall drilled lateral per foot from our rigs. And then we also saw about a 7% lateral per foot with our completion fleets. And if you really break it down, there's numerous things there. But we really think outside the box and try to take control of our business. One of the things we've done on the drilling side is we stood up a drilling motor program. And the reason for it was we were having failures and we wanted to be able to stay on bottom longer and drill faster.
That's exactly what we've seen by taking control of that. Also on the completion side, we've also expanded out Super Zippers. So we're able to gain efficiency there across all of our fleets and then added in more electric fleets. We have about 75% E-fleets, which have quite a bit more horsepower and allow us to pump at much, much higher efficiencies. And then I'd say the third piece, which you've really seen in industry, is lateral length. People have really started pushing lateral length out there. And we're really no different in all of our basins. So on average this year, we're increasing our overall lateral length by about 10%.
When you look at that, as you touched on, we're going to be able to do the exact same lateral foot this year as last year with four less rigs and two less frac fleets, all for the same kind of growth rate of 3% oil and 6% on the BOE.
Okay. I want to delve a little deeper in the Delaware Basin. You and the team have introduced a new completion design, which is supporting higher initial oil recoveries from some of the deeper zones. Can you talk about some of the technical changes that you've made? I have a couple of follow-ups.
Yeah, sure. So we haven't said exactly what the design is. And it really has just become part of our standard operating around in our basins. But what I will say is we're not just changing one variable. It really is all the way from the way we have to build a location to the surface equipment to how we drill the well to the well bore construction and to how we complete the well. It's all different across the board. And it does have a very slight increase in AFE of about 5%. So we've got to be very critical and test where we apply it. But luckily we've seen in most of the areas we apply it, we do see some benefit either from a production uplift or overall cost.
So what we did with it is we first started using it in the Eagle Ford and saw a slight uptick in overall productivity. But we really saw efficiency gains there. So moved it out to the Delaware. We used it in the Wolfcamp. The Wolfcamp, we saw a 20+% increase in overall well productivity. And that's early time all the way through midlife and full EUR of the well. So this is true recovery factor uplift. So obviously from there, we went ahead and we've expanded in our portfolio. We're testing the shallower targets all the way through the Permian and some with very good results. We're really seeing that it works in tighter rock and a little bit higher pressure. So we've tested it up in the Powder River. We're currently evaluating that.
In the Utica, we've actually right from the beginning of appraisal and testing, we've actually implemented the design with great success. We're currently in process of testing it down in Corpus. It's really just become part of the portfolio. It's really been a great needle mover, as I said, on that recovery factor.
Okay. Talk to us about the Eagle Ford. I know there's been some investor concern over the last couple of years as productivity has come down. But I know that one of the things you guys highlight is you're still getting really, really good returns there. And then maybe a follow-up is there's been maybe a shift in industry activity towards re-frac opportunities in the basin. So do re-frac fracs compete for capital at EOG?
Yeah. So the Eagle Ford, we've been drilling in for 15 years. It's no secret. The better actual geology and a little bit better reservoir tends to be in the east. And that's where we started drilling. We still have quite a bit of acreage left in the east. But as the years have went on, we've slowly moved out to the west, what we call the Western Monocline, which doesn't have as much structure in the rock as we said isn't quite as productive, but it's still very good. But what we found is over that 15-year period, as we evolve our technology and continue to innovate our completions and how we drill the wells, we're able to apply that in the west.
As you stated, we're actually getting better economics and returns over the last handful of years than we have in the 15-year history of the play. So it's extremely exciting. We've still got quite a bit of running room there in the Eagle Ford. And you mentioned re-fracs, which we know quite a few other of our peers are utilizing. What we see is there are re-frac opportunities, but the technologies are still evolving there. And for how we want to maximize complexity near well bore, it's very tough with a re-frac. And with our robust inventory and our quality of acreage, it's easier for us to go in. And we can get much better returns just by drilling a new infill well or a new offset well to that depletion.
Okay. Let's talk about Dorado. You talked about just given the early year gas macro, you dialed it down a little bit in terms of activity. But give us a sense of kind of the learnings, kind of the midstream strategy you have. You have a pipeline that you're constructing and it's going to help your net backs over time.
Yeah. So as I said, down in Dorado, it's in Webb County. And basically we had 160,000 acres. And it's a 21 TCF gas discovery. And really what it's like is standing up our own separate gas business down there in South Texas. So currently we're running one rig down there. We did pull back a little bit. We wanted to maintain that one rig so we can continue to learn, make sure we maintain all those synergies that we've gained out there and keep pushing the play forward. But what we're really looking to do there is as far as growth. And when you look into the future, the beautiful thing about Dorado is it's very prolific. The wells come on about 20 million a day. And you can hold them choked back for six months and they'll just stay flat production.
So you really don't have to drill that much to bring the volumes on. And then as you talked about just kind of our strategic approach there from an infrastructure standpoint, we found that we had an opportunity. Obviously we work with multiple third parties. We look at what the opportunity there. And we found that we could do it substantially lower cost down there. So we decided we went out and procured pipe, which we were able to get from a fairly famous canceled pipeline project for pennies on the dollar. So we got the materials fairly cheap. And we're building a 100-mile 36-inch pipeline from Webb County over to Agua Dulce, which is the market center. And that will be complete later on this year. And that just gives us all sorts of flexibility.
We actually see through both price realization and through GP&T reductions, we get it back about $0.50-$0.60/MCF. Now when you're talking about a 21 TCF resource, I mean, that's huge margin expansion over time that we see there. And then we can actually, we're right next to the coast, which we've got close to a BCF, right around 900 million a day of export capacity of LNG, which is by no means tied to this play. Any one of our assets can send gas to it. But it is great optionality. And we think it truly is the lowest cost gas closest to market in the U.S.
Great. Jeff, I was wondering if you could provide an update on your delineation program in the Utica Shale?
Yeah, sure. So the Utica, I mean, in my time with the company, it's probably the most exciting exploration play that we've had. I mean, people have been looking for it for about 15 years. And we finally kind of cracked the code on it. So we've accumulated 435,000 acres there in Ohio, right in the volatile oil and the oil window. And what we did was preliminary is we had geologic data on the east side of this acreage, more in the volatile oil window. So we had seismic, which is obviously very important to be able to understand and start appraising any kind of prospects. So up and down the eastern portion of the acreage, we drilled delineation wells. And then we've moved into actual spacing tests. And have pretty much performed that in the north, the central, and the south, and with outstanding results.
We've talked about two packages we brought on, one up in the north and one in the central, that are beating our expectations on type curve. Then we have an additional package, which we brought on here in Q2. It's the White Rhino you talked about, which we're looking forward to talk a little bit more on our next earnings call. But we're very excited about the results there. The go-forward plan would be once we get to the east side and we understand the spacing, we'll move into development mode there. And we're going to go ahead and shoot the seismic on the western portion of the acreage as you move into the oil window, which it does shallow up a little bit, but it's also just as thick. And it looks like very, very good rock.
We'll move into starting to delineate that once we get that seismic shot out there.
Got it. Can you talk about your ownership of minerals and how that kind of helps your economics in the Utica?
Yeah, this is very unique because, I mean, we always like to go out and buy minerals, but it's tough to find a large amount of minerals. What we were able to find was there was a large acreage holder in industry that actually had minerals there in a unit. It was 135,000 acres of minerals in the south. We were able, when we went in and we actually acquired their acreage off them, we got the minerals. That minerals we bought for about $1,800 an acre. So you can just imagine when you're able to increase your NRI there and you're just about 100% working interest, 100% NRI, it's a huge uplift on the economics, which makes that 135,000 acres extremely attractive.
Okay. I want to shift gears and maybe talk about marketing. EOG has had a long-term marketing agreement with Cheniere, as well as some physical sales agreements. Could you maybe unpack some of the marketing agreements and how those increase over time?
Sure, sure. So initially we kind of dipped our toes in the water with Cheniere. And we did a 15-year agreement. And what it is is we are actually exporting right now 140,000 MMBTU. And we've been doing that now for a handful of years. And just off that 140,000 MMBTU, we've seen about a $1.1 billion revenue uplift. And the reason for it is, with the agreement, we're able to elect on a monthly basis to either JKM markets or Henry Hub. And also with that agreement, we have an additional, with their next stage three when it comes on, that 140 under the same terms will go to 420,000 MMBTU. And then in addition to that, we have another 300,000 MMBTU that will be linked directly to Henry Hub.
So in order to continue to diversify, and we're always looking for unique marketing agreements to be able to insulate ourselves through kind of the cycles with gas, we just recently announced an agreement with Vitol where we took out 140,000 MMBTU, which is Brent-linked. So we're able to take some volatility out being Brent-linked there. And then there's an additional 40,000 a day that's going to be tied to Ship Channel there in Houston. So like I said, that's about 900 million a day that we have current exports. And we're continuing to look at agreements up and down the coast to be able to leverage and be able to get really kind of premier price realizations on our gas.
Okay. On a recent conference call, Cheniere highlighted the potential for an early startup of Corpus Christi Stage 3, which you just talked about. If it does start up early, would your marketing agreement kick in early under that theoretical?
It would. As soon as the agreement, the volumes come on. And a lot of times, just for note, it's really tiered in. Full volumes won't come on. It'll be tiered in. And as for us and our forward guidance, we'll wait for those volumes actually to come on to really build it into our plan. But yeah, we're excited. They've been a great partner. And they've definitely been ahead of the curve with all their construction projects that we've worked with them.
Okay. And then one more question. And we'll turn it over to audience for Q&A. Can you just give us an update on the Beehive Prospect in Australia?
Yeah. Obviously with our international exploration here in the last few years, offshore Australia, it's on the Northeastern Shelf. We found a beautiful four-way closure that we think is liquids. And we've been for the last year and a half, we've been in the permitting process and working through the regulatory on it. And I'm happy to say we just recently received the permit on that. So the plan is to pull a rig in sometime around the first quarter. And we'll go ahead and drill an appraisal well in that. And from there, we'll move forward and evaluate what the prospect looks like. But obviously a lot of potential down there. And it just really shows how we can leverage that offshore experience that we have in Trinidad.
Okay. So you just received the permit. So you have essentially approval to go forward?
That is correct. Yep.
Okay. Great. Let's turn it over for Q&A. Just wait for the.
Yep. Yes, that is shallow water. Yep. That would be jackup territory. And one of the things that we look at when it comes to offshore, we want low cycle time. And really, when you get to the offshore or deep offshore projects, you tend to have much larger cycle time and a lot more risk. And really, we've seen our skill set on the much shallower water with the jackups. We can go ahead. We can get in there very quick. We can appraise it without having to spend hundreds of millions of dollars to understand what we have.
This is working. Hey, Jeff. Thanks for your time today. Congrats on the promotion. EOG, pioneer in many fronts of technology, one being pumping 100% 100 mesh in the unconventional revolution, doing it before anybody else. Now everybody's doing it writ large. The question is, did you do it for cost control? Did you do it because you thought big sand would impede the flow of liquids to the well bore or some other reason?
So I'm a completions engineer by trade. And actually I pumped the first full 100 mesh job ever in the Eagle Ford. And no, it wasn't for cost control by any means. Now don't get me wrong. Back then people were pumping ceramics and other high, high cost. But at that point, we had already moved over to natural sands. What we understood was with the actual rock makeup here in these unconventional rocks that are extremely low perm, you're not trying to get conductivity. You're trying to get connectivity with the rock. And the finer mesh that you actually pump in, you actually can create more fractures within the reservoir. And it's obviously got a lot more permeability than the natural rock there. So really it acts more as a diverter than actually a proppant that we know kind of in the past.
That's really one of the main reasons. Now a secondary benefit is 100 mesh is obviously at that time it was a byproduct. Now a lot of people pump it. So it's increased price. But it was quite a bit cheaper. That was kind of a secondary byproduct of it.
Yeah. Big believer that the liquid is as important as the sand to create the tortuosity in the reservoir.
Absolutely. I mean, we like to look at it not just from a sand or a liquid, but a total slurry sometimes too.
Any more questions? Great. Jeff, thank you so much.
Thank you.
Appreciate it, sir.
Appreciate it.