Neal Dingmann: No, I’m glad you’ve got you all, [indiscernible], but made return. It’s certainly notable. And then just a quick follow-up on your onshore. It seems like, I think in the press release, you suggested about 1/4 of the Eagle Ford would be on field development. Is that normal? And can you just talk about what that will be directed for?
Eric Hambly: Yes. We use that term field development Neal to count things that are mostly associated with just bringing on new wells, but they’re not specifically the drilling and completion cost. So if we have to build a pipeline to connect a new pad to an existing facility or if an existing facility requires some kind of upgrade to handle the new volume. So generally, it’s just surface equipment that we’re upgrading. It’s also we continue to make improvements in our greenhouse gas and methane emissions, and we’re spending a little bit of money there to drive those improvements in our Eagle Ford business. So it’s mostly just bringing on new wells, the surface equipment related to it, but a few other enhancements that improve our operations and lower our downtime and help us with our free cash flows.
Neal Dingmann: Thank you.
Operator: Thank you. Your next question is from Leo Mariani from Roth MKM. Please ask your question.
Roger Jenkins: Good morning, Leo.
Leo Mariani: Hey good morning. I want to kind of quickly follow up on the Gulf of Mexico. You kind of briefly mentioned this, Roger, but I don’t know if I’m looking at this right, but it seems like maybe there’s been kind of a — I don’t know, an unusually kind of high number of sort of well failures that have required workover of late — just wanted to get a sense if you guys are attributing that to anything in particular out there, maybe this is just kind of a recent bad streak of luck and just in the Gulf, I was hoping you could also maybe talk about M&A as I guess we’ve seen an asset trade lately and perhaps there’ll be others coming out of the Gulf?
Roger Jenkins: Thanks, Leo. That’s you said it right. It’s bad luck. It’s nothing to do with anything. These are not related. There’s a safety valve instrument in Dalmatian. This has been an occurrence that happened in the Gulf to various operators through the years. You test the safety valve from a regulatory basis and the valve won’t open back up for different kinds of reasons. Then we had to go do some studies about the metallurgy of the type of equipment we need, there’s very little equipment on the ground by these large service equipment companies today. You have to procure things, procure rig. You can get rigs in the Gulf to do work. We’ve been able to do it. It’s not that tight. We’re able to do it. And then the well in Neidermeyer is a complex deep pressured well that had a communication.
It looks like between the tubing to the casing. We bought this well. We didn’t complete this well. It wouldn’t have been the way we would have designed the well, we can say that. And we need to go fix the well, and we have a rig there today to fix it. These things are unrelated. And what’s really happening to us here in this first quarter is some work that needs to be done that we had to procure and get the equipment to do with large downtime, for example, they’re lifting up the famous subsea water injection equipment at St. Malo, which is a big deal for one of the greatest fields in the Gulf on the highest margin. Fields in the Gulf that has to be shut in and picked up. Delta House has some equipment that’s being installed by another operator.
So we have a lot of planned downtime that came in on top of some one-off workover leading to a low first quarter and we haven’t put a well online in onshore in quite a while. That’s the way we run our business to have this incredible low, free cash flow yield, incredible leading net debt to EBITDA, no bonds to be refinanced until 2027, the only energy company in that situation. So all that’s set up to provide all that safety for our shareholders, and we’re returning money to shareholders. So to wrap all this up, some poor luck, things happened with some downtime. As to M&A, thanks for asking that question. We are a company that prides ourselves in very successful M&A, over $8 billion of M&A in the decade here. We have an incredible team, a senior team, and we have a proprietary process to look at things on a certain basis.
The recent large deal is something that didn’t fit the criteria of us. We’ve known about the deal for a long time. And I think if you back up to 30,000 feet, what’s the difference is the debt-to-EBITDA level of the outcome of that deal versus us striving to be one times debt-to-EBITDA at $45 oil, not 1.6 net EBITDA at $75 oil. So we’re in a different total world. We have all the assets we need and we’re striving to protect our shareholders through large returns and cycle pricing and with this incredible balance sheet. So that’s kind of how we think it. So for us to do M&A, it’s a certain criteria of the age of the assets and the returns that we like that fit in with our framework, and we have — that’s how we judge that. And that’s the answer on that.
There are plenty of opportunities. We look at them all the time, and we’re very proud of our screening and our process that we have that’s led to a great success on M&A front here. One of our best things that we do actually. So thank you, Leo, for supporting us and calling in today.
Leo Mariani: Yes. I appreciate that, Roger here. Maybe just a quick follow-up on the Eagle Ford here. So it seems like you guys are somewhat electing to turn in line quite a bit fewer operated wells in 2024 versus what you did in 2023. And it seems like that’s really kind of leading to production ticking lower. Can you maybe just kind of talk through that a little bit? I know you’re bringing on a slug of wells kind of early in 2025, but just a little surprised to kind of maybe see some of the timing with a lot of fewer turning lines this year?
Eric Hambly: Yes. Thanks, Leo. This is Eric. I’ll just give you a little bit of my thoughts on that. In the Eagle Ford, we are expecting 30,000 barrels a day in 2024, down about 3,000 barrels a day from 2023. And we’re pulling back our capital program there just a little bit. Some of that’s driven by just the timing around when we’re bringing on the wells. We’re bringing on the average new well a little bit later this year than before. Capital decisions we made in 2023 had us entering the year without any wells to complete early. So we’re drilling wells in the Eagle Ford before we can complete them. And then we’re happy that we’re able to, within our overall framework, direct some capital investment to Vietnam for future long-term overly growth there with not changing our total capital level, but displace a little bit of Eagle Ford spending for Vietnam spending and set us up for a nice long plateau out there in Vietnam.
