EOG Resources, Inc. (NYSE:EOG) Barclays 2022 CEO Energy-Power Conference September 8, 2022 8:35 AM ET
Company Participants
Ezra Yacob – Chief Executive Officer
Conference Call Participants
Jeanine Wai – Barclays
Jeanine Wai
Okay. Good morning, everyone. Welcome to the 36th Annual Barclays CEO Energy-Power Conference. And it’s nice to see faces so early in the morning. It is our pleasure to have Mr. Ezra Yacob, CEO of EOG Resources, positions that he’s held since 2021. EOG, for those who aren’t as familiar, they are multi-based and large cap E&P. They have acute focus on shareholder returns, which we love. And the base dividend has grown 21 out of the last 24 years. It’s never been suspended or cut.
Before we get into our fireside chat with Ezra, we have three polling questions. So everybody has a keypad, press a number for your response. We’ll wait a couple of seconds and then the answers will be instantaneous. All right, first question please.
This is a fun one. Which energy sub sector do you think will outperform the most in 2023? Press one for integrated oil; two, for large cap E&P, three for SMID Cap E&P; four, for services; five, refining and six, clean tech; seven, midstream. I haven’t actually voted in three days. So I’m going to vote today. And I am biased since I’m a large cap analyst. Okay. It looks like large cap and services kind of split. Yesterday actually, it was much tighter, was the majority of the people think mid cap E&P.
Next question, please. Which energy sub sector do you think will outperform the least in 2023? Integrated oil, number two large cap E&P, three SMID Cap, four, services; five, refining; six, clean tech and seven midstream. And don’t take it personally, Ezra, if its number two. Okay, clean tech. That’s almost exactly how the answers came out yesterday. I think yesterday was like 65% said clean tech would underperform.
So last question. We’ve had some debates on this one. So I figured we throw it up here. In 10 years, the LNG market will be; one, under supplied; two, over supplied. Okay, I voted too as well. 71% said over supplied. Interesting, we’ll see how that shapes up. Thank you, everyone for participating. And hopefully, we will publish all the results from all of the polling questions next week.
Ezra Yacob
Good questions. Yes, no, that’s great.
Jeanine Wai
Okay. So, Ezra, we’d love to just set the macro stage here. And if you could provide your latest thoughts on maybe global supply demand, and where you see oil growth going?
Ezra Yacob
Yes, we entered the year kind of building our model from kind of the field up. So looking at constraints on services, rigs, [indiscernible], sand, trucking, things of that nature. And so entering the year, we had forecast U.S growth, our internal model is kind of on the lower end of most of the forecasts that are out there. And things have started to trend down a little bit to kind of the 700,000, 800,000 barrel per day kind of year-over-year type of growth range. And that’s what we think is really going to continue forward.
And probably heading into ’23, we’d be a little bit lower also, not only do you have these supply chain constraints, but you also have the inflationary pressure. I think what you’re seeing is out of the public companies, you really are seeing discipline stick, and you’re seeing discipline being rewarded. And I think the companies that have ourselves included emerge from the pandemic and much stronger shape are really reevaluating the old business model and how much they want to lean in to an inflationary environment. And then on top of that, like I said, you’ve got the supply chain constraints.
So I think U.S oil growth is probably going to end up being our model is a little bit on the lower end of the growth cycle. On gas, it’s a little bit different. Of course, you have the associated gas, that’s going to be muted because of the oil growth, obviously. But on the gas side, we actually see more of a fundamental shift on really the demand side, growing Petrochem market, LNG coming on in the next few years. And then, of course, coal switching, which I think has been a bit more dramatic than anyone really had anticipated this year.
And so from that regard, we got — we feel pretty bullish on the gas side as well. And with growth in the gas side next year, essentially starting with the associated gas probably being a little bit on the lower end of a lot of expectations as well.
Jeanine Wai
And you’re in multi based and we’ve had several CEOs comment over the past couple of days, that the private activity does seem most recently to be kind of slowing down and it seems to be a variety of things. Some of it is just still unable to have access to by not necessarily not having access to rigs and [indiscernible] things like that. But everything else in the supply chain, and some of its in price. Does that match kind of your view on what you’re seeing?
Ezra Yacob
Yes, I think that’s right. The large, the public companies have kind of kept a steady state of activity throughout the year. I think most of the companies with size and scale that we’ve been able to maneuver around and get the supplies and navigate the supply chain headwinds. But on the private side, I think that’s exactly what we’re seeing is that there’s a little bit of a duct build [ph] on the private side, not so much on the public. So when you roll it up together, it looks a little bit more flat. And yes, it’s basically being a bottleneck kind of downstream moving upwards, whether it’s access to sand, or trucks or things of that nature, or just horsepower also frac spreads.
So while the rigs are being dominated, especially in the Permian by, a lot of private operators, it’ll be curious and interesting to see how much of that really translates into U.S growth in the next couple of years. And part of the reason to is, a lot of those private companies are really small scale, right? And that’s why they’re having a difficult time getting some of these supply chain issues worked out. And these private companies are also a little bit they’re kind of late comers to the basin. And so oftentimes their acreage position or where they actually have their rigs is not necessarily on what we would say is growth inventory, right, or high quality acreage.
So definitely acreage where you can drill some wells in [indiscernible] returns at these prices. But is it the type of quality acreage that can actually grow significant volumes and not? That’s not really what we’re seeing, like that’s evidenced again by a bit of a disconnect with the whole historical kind of rig versus oil growth rate coming out of the Permian.
Jeanine Wai
Yes, several CEOs have taken the under on what on the rig count increases that some of their reports, they’ve been reading, similar commentary. And sticking on the growth side of things, you mentioned the public reevaluating the old business model here. On the earnings call, you commented that oil growth was going to be probably at that time on what you’re seeing similar employee [indiscernible] to what you’re seeing what you’re doing in ’22. I know, it’s very stale. It’s probably 2 years old at this point. But the old data point was EOG, was contemplating that 8% to 10% oil growth was the sweet spot for efficiency. And that also was predicated on the macro, and the macro arguably looks a lot more constructive now than it did then. What other factors kind of went into your decision to downshift from a sale, admittedly, 8% to 10%, to call it 4% or low single digits.
Ezra Yacob
Yes, so that’s right, Jeanine. So we said on the earnings call, things stay where they are next year’s old growth probably be similar to this year’s. And really, so every year, it kind of — it starts with the macro environment, which you’re right. And the three things we’ve talked about historically is, demand getting back on track to pre-COVID levels, which demand has been steadily growing, it obviously has some pauses, some pullbacks here and there, but in general, it’s going in spite of COVID lockdowns in China and recessionary fears, demand destruction fears, things of that nature, but demand is continuing to increase.
Inventory levels at or below the 5-year historical average, which they’re at even though it’s been building from dominantly from the SPR, right, transferring from the SPR inventories, and then spare capacity, which I think we all without any real clear line of sight, we can all kind of tell that that’s backed down to historic lows as well. So the macro, I agree with you the macro supply and demand fundamentals look very positive. But there are two other things that we look at.
The first is kind of the macroeconomic environment, which right now we just got done talking about supply chain logistics and having to lean in into an inflationary environment. So that’s a big factor in our decision. And then the most important one is just our internal discipline. Once you kind of work through the external, where are we at internally. And as you said, we’re a multi basin operator. So we’re in the Permian, in the Delaware basin side, we’re in the Eagle Ford. We’ve recently highlighted both Dorado, the South Texas Natural Gas play, the south Powder River Basin, as a combo plays what we call it, and the North Powder River Basin, which is also an oil play. And then we’ve got some Bakken and some more legacy assets as well.
And so when we think about every year is, what part of the lifecycle of each of those assets and how much capital investment can they actually handle to the point where they’re getting better every year. Now, in each of those, we could easily throw a lot of rigs and a lot of frac spreads and activity at them. But especially in an inflationary environment like this, you could see how it would be easy to erode returns in each of those plays. And I’m not talking about cash on cash returns just a direct rate of return because of $83 oil, I think is what it was this morning when I woke up. You can generate some cash and some returns. The challenge becomes on the cost reserves and that binding costs and what are you doing on your operating cost side. And each of those assets are you lowering the cost basis of the company for the future, or are you increasing it. And that’s really where the discipline — the definition of discipline comes for us.
So when we look at where we’re at in each of those plays right now, we look at the macroeconomic environment as far as supply chain issues, logistics, things like that. I think the pace that we’ve run at this year has been very, very positive. And that’s kind of where we start on the oil side.
Jeanine Wai
And then the old plans called for natural gas do outpaced growth in oil. Is that still a potential new brand [ph]?
Ezra Yacob
Yes, so on the gas side, and again, we talked about this on the call a lot of it so obviously, there’s the associated gas with our oil growth. So let’s talk about actual gas plays and which is Dorado and internationally in Trinidad. Dorado, I think as everyone can tell over the last few months, we’ve been talking about it highlighting it, we couldn’t be more pleased with our progress there. We think we’ve discovered over 20 Tcf down in South Texas between the Austin Chalk, the lower Eagle Ford and upper Eagle Ford reservoirs. We love it, because it’s got a low cost of supply. It’s in Texas, it’s close to the growing demand centers along the Gulf Coast. And we’re very excited about the pace that we’ve been improving that our costs, individual well costs and individual well productivity are really outpacing what we would typically think of, for a resource play this early in its life. And so it will definitely demand a bit more capital investment.
In fact, next year, we talked about on the call, we’re going to advance some infrastructure spending in the next year to go ahead and set the play up for additional reinvestment in the future. So gas, yes, could on the heels of that outpace oil growth. And then in Trinidad, we talked about last year that we’ve made two discoveries. And we’ve actually finished setting a platform in Trinidad this year, or over the summer we will and so we’ll start drilling out there. And we’ll have some gas growth associated with that as well.
Jeanine Wai
And then last one on growth, maybe its own growth and efficiencies. So a couple of years back when there was a more spirited debate over higher growth, lower growth and what the proper business model was. And we love our models and the excel math said that higher growth, okay, you get less free cash flow in the first couple of years. But there’s a crossover point and ultimately, you get more and EOG is a long-term value focused company. And so at the time, it was, in your view, I thought, I’m putting words in your mouth, it was the right effort to have maybe a little bit more growth than what some people were expecting. Now the interesting part of that exercise is that I remember we wrote a note about it, oil was like 60 back then, or something like that. Fast forward to today and let’s just say we’re bouncing between 80 and 110, that crossover point is really pulled forward and efficiencies have gotten better. So if we were to kind of think of EOG in a more normalized environment without the supply chain issues going on, what is the optimal growth rate for EOG now in that more normalized environment?
Ezra Yacob
Yes, so I think one thing to — one thing that we’ve learned, and we’ve demonstrated to ourselves through the — through 2020, through the pandemic is that even in a maintenance capital case, we were able to expand our future free cash flow, simply by lowering the cost basis of the company. So that’s the discipline and that goes back to what I was talking about is investing in each of these plays at an appropriate pace where they’re getting better. So that’s one way to expand your free cash flow or your cash flow. And then obviously, if you can layer in some growth on top of that, it’s significantly better. Those are really the governors for us.
So again, when we sit here today and think about putting in infrastructure or steel or drilling some of these wells into a higher refining cost, ultimately a higher well cost or higher refining cost environment, that’s where the capital allocation, and the decisions really come is how far do we want to lean into that? How much of it can we offset on the cost side? How much can we offset with well performance, because those are costs that are going to stick in your company, for here going forward. But you’re exactly right. That’s still how we approach it is what’s the balance between optimizing your near-term free cash flow generation, while not stealing from your future free cash flow potential.
Jeanine Wai
And then on the cost side, we’ve heard a lot about scale, consistent programs over the past few days being one way to help mitigate inflation and becoming a partner of choice with your service companies. EOG clearly has a lot of scale in the Permian. Maybe not as much scale in your other basins. So our question for you is, how much of a bargaining chip is actual scale considering that you’re running smaller programs outside of the Permian?
Ezra Yacob
Yes, scale is important. So in our two biggest ones, Eagle Ford and Permian, we’ve got enough scale to kind of leverage. The other thing that we’re able to do is leverage actually between the multi basins. Not everyone, even on the service side wants to have all of their opportunities in a single basin. So you also get a leverage by being a multi basin operator, not only on negotiating for things, but quite frankly on just data collection and learning.
When you become a specialized or singularly focused on a single basin, it’s very — it becomes very difficult to kind of innovate. And again, not only just on the operator side, but for service companies as well. Being able to work across multiple basins, provides a lot of opportunities to continue to get better. The scale for us is, it comes down to gaining efficiencies. At the end of the day, this is a people business still, it’s people in the field. And so being able to give them continuous operations, continuous environment to continue to increase efficiencies and get better at their job, that’s really the type of scale that we look at.
There are benefits from sand and negotiating and things like that. But ultimately, the way that we focus on driving our well costs down is through efficiency gains. It’s not through trying to leverage our size and scale. When we do that, for negotiating, we typically try to leverage our size and scale on is more for highest quality equipment, and higher performing crews, longevity of contract, while still maintaining some flexibility in those contracts. We think of that, that’s what sets our team up for success is being able to have a consistent program, even more so than scale, where they — you can really allow the engineers, the geologists, the people in the field, really begin to drive down well cost through efficiency gains.
Jeanine Wai
And then just sticking with efficiency gains and driving down costs, so giving credit where credits due, EOG, in our opinion, has done the best job at holding costs down this year. You recently indicated that you’ve done a good job by pulling forward efficiencies. But some things are just a little bit higher costs than expected. So you no longer anticipate you’re going to be flat this year. Just so that we get the baseline here, when you had anticipated that well costs would be flat year-over-year, was that like a weighted average for the company? Was that in every single basin?
Ezra Yacob
Yes, so what we do with it typically is a weighted average costs of the wells based on activity level across the company. And you’re right, we entered the year, really anticipating about 10% to 15% inflationary pressure. And we felt that between kind of the way we are finishing the year with efficiency gains kind of line of sight things that we had, working inside the company, including things like sand and drilling mode performance and a lot of ancillary items, we thought we’d be able to offset that 10% to 15%. That was pre — the invasion of Ukraine, though. And that has directly added as much as 510, maybe 15% inflation on top of that. And that has been a bit too much for us to offset.
So we’re anticipating this year, we’ll probably finish with modest single-digit percentage year-over-year increase. And then going into next year, again, if things — last thing I want to do is try to make a call on drill piper casing at this point. But if things kind of continue as they are, we might see similar types of increases next year as well.
Jeanine Wai
We did do a polling question. Today’s answers and yesterday’s answers, I think I said earlier, they were like 20% was the investor expectation. So we’ll see where it ends up. And just to address some of the concerns out there, again, victim of your own success, and I’m sure you’ve heard this already before, there’s some concern that EOG did such a great job at bottom taking some of the phrases for this year, that you will see relatively higher inflation next year relative to peers. And we’ve seen some of this in other companies, some companies have nuances in their contracting where their contracts aren’t rolling off till the end of this year or early next year. So they’re marking up to market all at once versus others have been renegotiating all year. And so it’s like a different year. How do you address concerns that might see more inflation?
Ezra Yacob
Yes, our contracting hope we won’t, is the simple answer. As we said, if things continue as they are, we’ll probably see potentially kind of single-digit year-over-year increases again next year. That’s kind of line of sight that we have this right now on it. And the reason for that is our contracting structure is similar to what you said, we don’t contract on a calendar year or 12 month period or anything like that. Similar to how we do a lot of our marketing agreements, we stagger our contracts. So at any given moment, the positives and negatives of that is at any given moment. We’re kind of in the market looking for opportunities. Sometimes it moves in favor with us, sometimes it moves away from us. I think in any given year. That maybe a fluctuation of a couple of percent.
If you go back to 2020, when the market rates were crashing for services, that’s one reason our costs didn’t drop as aggressively as everybody else is that we’re carrying higher costs through that. But again, we dropped our call [ph] set here, approximately 9%. And the way we did that is through efficiency gains. So again, when we think about well costs, we really don’t lever or lean into contract pricing to get our well costs down. When we think about measurement of premium wells, or double premium wells and the well costs associated with those in our type curves, if our engineers tell us that, hey, we just got a great deal, it’s going to last 3 months and lower our well cost, we don’t necessarily think that that’s a sustainable deal and start saying that those wells are premium.
We really work as I said, to structure our contracts in a way that put us in a position where we can get sustainable well cost reductions. And that is basically it’s not really any more complicated than time on location. And so the less time you can spend on location, the less your well cost is going to be in general. The best thing we can do is contract with flexibility, depending on what the markets doing. But ultimately try to get continuous operations with high performing rigs and crews. And then we utilize technology, typically internal technology to try and again, put everyone in a position to really excel.
Jeanine Wai
I’d love to turn to your assets and talk about co-development. So we’ve had a couple of conversations over the past few days about inventory, co-development, type curves, one of your peers in the U.S type curves are just going down and part of that is more co-development. It has been discussed in some of your peers in the Permian, more so on the Midland side than in the Delaware where you are. But I was wondering if you could just tell us how much co-development you’re doing in the Permian currently?
Ezra Yacob
Yes, I’d say that’s our whole program is basically co-development. We have a different approach, kind of like we just said on well cost, it is a legitimate way to drive down well cost by getting into manufacturing mode and saying, okay, we’re going to co-develop here, and this is what we’re doing and try to get it. That also stifles innovation and sometimes can lead to kind of cost creep or leakage out there.
What we do is across any of our plays, including Dorado, where I just talked about, we’re already starting to explore kind of the lower Eagle Ford, upper Eagle Ford and Austin Chalk, and we’ve had co-development, Eagle Ford oil window, and definitely in the Permian is, we really look at it. We start with the geology, the subsurface data, and we don’t have a set standard of what development units or what areas need to be co-developed, at what space and which targets and a specific way, each of those are really done by custom analysis.
So we look Permian is very special, it’s got basically a mile as everyone knows, have multiple targets in there that you can land in, on the Delaware basin side. So the first thing we start with is we look for natural containment barriers. So places in the rock where you can develop one section without necessarily affecting another. And then from there, you can start to break down which targets need to be developed together and which ones don’t. That also, as an extension of that determines how long of our laterals we start to drill, right?
The geology, we think is pretty dynamic. It changes quite a bit. And so when we’re developing a specific landing zone, we want to make sure if we’re drilling either a mile or mile and a half or two miles out that we’re going to be in that specific zone, and being the same rock type that we’re [indiscernible]. We’re going to finish the well and that we actually started in. So for us, it’s just a lot more of — that’s where the science, that’s where the technology really develops. And that’s just our frontline employees kind of digging into the details and figuring out what’s the right development on essentially every single drilling unit.
The goal, again, is to kind of optimize that NPV per acre, right, balancing the recovery versus your returns. Because once you kind of develop these things, it’s very, very difficult to go back in and try to develop after the fact.
Jeanine Wai
Okay. We only have five minutes left. So I’d love to turn to the balance sheet and then hit on iSense. So on the balance sheet, you’ve got $1.25 billion coming due in Q1 ’23. Got loads of cash right now. Your next debt maturities are until ’25, ’26. Very manageable, [indiscernible]. Is there any appetite to take out and reserve cash for those debts [indiscernible] earlier?
Ezra Yacob
Yes, there are key pole provisions on those maturities to begin with. But no, at this point, there’s not really, we’re focused on going ahead and retiring this upcoming bond. And then we’ll be in a good position as far as our balance sheet.
Jeanine Wai
Hey, we’ll cross that off the list and then we’ll move to operating cash and reserve cash. Prior commentary about $2 billion or every day working capital stuff, and then that also included some bolt on [indiscernible] opportunities. We’ve been very surprised at the A&T [ph] market. Has anything changed either in the operating environment or in your bolt on opportunity that would cause you to [indiscernible] or decrease that $2 billion estimate?
Ezra Yacob
Yes. Well, it’s definitely gotten more expensive to run the business. Working capital obviously moves around a lot more. But that’s still a pretty safe estimate for the reserve cash, that we like to have to kind of run the business. And then on top of that, we have a $5 billion share repurchase authorization we’ve talked about. So we’d like to have some cash on hand to be able to manage that. In general, I’d say, we’re not afraid of building cash on the balance sheet in this environment. We think it’s a — we think, again there are two things that really make a company special, that really sign, or a hallmark of a good company. And the first is sustainably growing base dividend, we covered that. That’s what we strive to do. And we hope that that tells our shareholders, our investors that that’s the new level of confidence for the company going forward. That’s what we see from increasing capital efficiency going forward, that that’s our commitment. And as we started off with, we’ve never had to cut the dividend after paying one for over two decades.
The second thing on top of that is a pristine balance sheet. And we think having a pristine balance sheet is, especially in a cyclical industry, like ours, is a very significant advantage. And we’ve gone to the balance sheet during downturns. We went to it during the pandemic, when we needed to. It’s one way that we support the dividend. But it also gives us the advantage of counter cyclical opportunities, opportunities to invest and grow the company, grow the future cash flow potential of the company.
Jeanine Wai
And so based on our forecasts — pricing, we don’t see you getting to $2 billion plus already earmarked 1.2 sides of the debt, $2 billion plus $5 billion, so we don’t see you getting to the $7 billion until sometime in the back half of next year. Should we think about the timing of reserving that amount and the upside to the 60% as related?
Ezra Yacob
No, not necessarily. The cash return model and the special dividends that we pay out, the Board looks at that at every meeting, every quarter, they evaluate our cash position, they evaluate the macro environment. And the commitment that we’ve made is really a minimum of 60% return to the shareholders inclusive of that regular dividend. So really it comes down to just the environment that we’re in at the moment when the Board’s looking at it. And the last thing I’d follow-up on is that is an annual kind of guidance. It’s not specifically a quarter-by-quarter.
Jeanine Wai
And I’d love to end on iSense, which is your continuous methane monitoring system that you’ve unveiled at least publicly in 2Q. Can you talk about how that system that you developed is different from the other commercial ones out there?
Ezra Yacob
Yes, the biggest thing about it is, the sensor is essentially the same. We’re constructing our box by ourselves, obviously, internally, and so we’ve cost savings there. But ultimately, the real benefit that we see on this is that it’s plugged into the rest of our real time automation and monitoring software and measurement tools that are on the facility. So instead of just having an alert that there’s some sort of intermittent methane release, we can actually tie it into other things going on location, whether there’s high line pressure, or an event where the well happens to be slugging or something like that. So it really ties into the rest of the datasets that we have available to us. We think eventually, that’ll help kind of direct us to help prioritize maybe some of these events, it’ll help us to potentially lead to producing wells, potentially better and may lead to a better design of facilities, which would ultimately be the best thing about it. So it’s a great piece of software and data. And again, the fact that it ties into the rest of our systems is really what makes it unique and kind of delivers the value for EOG. It’s monitored 24/7, real time bar control rooms, internally. And I think as we pointed out on the call, we’ve already covered about 60% of our Delaware basin production with iSense. And we’re trying to roll it out aggressively across the rest of the company as soon as possible.
Jeanine Wai
Well, on Tuesday, leaving [indiscernible]. On Tuesday, one of the polling questions was good E&Ps have at least Scope 1 net zero targets and 75% actually asked this question twice. 75% of the responses were yes. So you’re well on your way.
Ezra Yacob
Good. Good.
Jeanine Wai
All right. Well, we are way out of time. Thank you so much. This has been a real treat.
Ezra Yacob
Thank you. I appreciate it, Jeanine.
Question-and-Answer Session
Q –
[No formal Q&A for this event]
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