Doug Leggate: So Tim, I don’t know if this one’s for you or for Ezra, but your comments about being able to offset some of the inflation have been a fairly consistent part of your message over the last year. So, I think folks were a little surprised by the CapEx number. So I wonder if you could walk us through the moving parts of whether it be activity led or more specifically, infrastructure related to some of the newer places? There are disproportionate amount of takeaway spending has maybe lifting the CapEx issue. I’m just curious on the breakdown.
Billy Helms: Yes, Doug, this is Billy Helms. Let me take a stab at that. So first, there’s probably three buckets you can probably put the increase in. First of all, is inflation in our well cost. That’s probably a good piece of it, 1/3 of it. It’s about — we’re anticipating about a 10% well cost inflation in our program versus last year. And yes, that’s maybe 10% over and above last year. But still last year, we achieved only a 7% well cost increase in spite of probably, arguably, 15% or 20% inflation. So I think our teams have done a great job on offsetting inflation with efficiency gains. We’re expecting more of that this year, but we’ve baked in about a 10% cost increase. The second part of that is going to be infrastructure.
We’ve talked about already our Dorado gas pipeline. That’s been initiated. And we’re also building out some infrastructure in some of our emerging plays, like the Utica to start the testing of those plays. And then we’ve also included some capital for our ESG projects that we’re advancing. So those are kind of the buckets that we look at. And then obviously, we have some additional wells on top of that in these various plays. So as we pick up the two additional rigs and one extra frac fleet, of course, that’s going to accompany some additional well count. So those are the three main buckets that I would characterize the increase in the capital versus last year.
Doug Leggate: Okay. I appreciate the color, Billy. Thanks for picking that one up. My follow-up is probably for Ezra. And Ezra, forgive me for this one, but I want to take you back to pre-COVID when EOG was growing quickly and frankly, a market didn’t need the oil. But you could make the case that today. We’ve got a market that doesn’t need the gas. And I understand your point about maybe trying to take markets, some others are cutting back. But the fact is we still have a largely stranded market in the U.S. Why is this the right time to accelerate your gas production given what is a potentially very constructive outlook longer term?
Ezra Yacob: Yes, Doug, that’s a good question. Yes, I think the difference is between 2019 or pre-COVID with the oil versus what we’re doing in Dorado right now. So like I said, the Dorado volumes are anticipated to support. It’s basically the output of a single completion spread program this year. And the benefits that we see of running a consistent program there to learn about this asset, continue to drive down costs, support putting in some infrastructure, things like water takeaway and in-basin gathering, that outweighs the near-term volatility in the gas price because what we see is in a very not-too-distant future, we see a pretty dramatic increase in the offtake and the demand coming on along the Gulf Coast. Now we are backstopped and supported, obviously, with investing on the return side in these premium wells.
So we measure the investment on here at a $2.50 natural gas price. And while at today’s prices, that’s below, we run that $2.50 all the way through the life of the asset. The rest of the gas that we’re growing this year is, honestly, as we — as I said at the top of the Q&A is really associated gas coming out of the Delaware Basin, where the returns there are dominantly driven obviously on the oil and liquids side. And we’re really running a maintenance program or a flat activity level program to Q4 across the Delaware Basin.
Operator: Our next question today comes from Leo Mariani from MKM Partners. Your line is now open.
Leo Mariani: I was hoping you could update us a little bit on maybe some new well results, if there are any from some of the emerging plays. Most interested in hearing about any recent Utica well performance or any Utica wells that may have come on? And then similar, just in the PRB, did get a sense if you’ve seen improving wells there as well. You’ve talked a lot about cutting costs in PRB, but just curious as to whether or not some of those wells have seen improvements as you guys have gotten more experience?
Ken Boedeker: Yes, Leo, this is Ken. I’ll take the Utica portion of that. The four wells we drilled and completed in ’22, really continue to deliver our expected performance. And just to give you a flavor on that, we anticipate starting our drilling program for ’23 at the end of the first quarter here. One other thing, I would note in the Utica, not on the well side, but on the acreage side is we have added about 10,000 acres of low-cost acreage store position, and we’ll continue to look for additional opportunities to add to that position. So we’re really excited about the Utica plan for 2023. I’m going to go ahead and give it over to Jeff now for the Powder.
Jeff Leitzell: Yes, Leo, this is Jeff. Yes, just a quick update. In 2022, we continue to delineate our acreage there in the Southern Powder River Basin. We completed about 31 net wells across the four primary targets. And all of those, we had excellent results. And we’ve been shifting our primary focus there, as we’ve talked about previously to the Mowry. So in 2023, we’re going to ramp up the activity a little bit there. We’re going to run kind of a consistent two- to three-rig program with one frac fleet. So that will be about 55 net wells. And the majority of those, as we talked about, will be in the Mowry. It’s about a 75% increase year-over-year there in the Mowry. And then we’ll continue to focus on optimizing that Mowry program there in our Southern Powder River Basin core area.
We’ll collect a lot of valuable data, and then we’ll look to utilize it in the future on our overlying Niobrara formation and then the North Powder River Basin position that we announced earlier on.
Leo Mariani: Okay. That’s helpful. And then just wanted to jump over to the Eagle Ford. If I look at the Eagle Ford, production has kind of been steadily dropping in the last few years. You guys have picked up activity pretty significantly in ’23. It looks like roughly 50% more net completions this year versus last. In your prepared comments, you signaled basically trying to kind of keep Eagle Ford flattish for a number of years sort of going forward. Just wanted to get any additional color around that? Eagle Ford had kind of been in decline in favor of other plays, primarily Delaware. And now the plan is to kind of flatten it out. Are you kind of seeing new things there in terms of well productivity or lower costs that have got more encouraged about the play? Just wanted to get a sense because it seems like maybe it’s risen slightly in the pecking order here.
