Tom Jorden: Well, geology is complex across our portfolio, and if you don’t have to catch myself or I’ll spend the rest of the call talking about geology. But what’s most important is that, we’ve tested this section, we’ve got a lot of calibration and we understand the stratigraphic variation, we understand the oil gas complex ratio variation, we understand the pressure and drilling challenges. So I think we’re highly calibrated. So, look, complex geology is a bigger issue at the early phases of development than when you’ve got that calibration and we feel really confident that we understand the geological overprint.
Operator: Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.
David Deckelbaum: Thanks for taking my questions, everyone. I was curious just if you could go into just, obviously, the program this year is shifting more or I guess it’s high grading a bit more into the lower Marcellus. I think in your multiyear outlook, you sort of assume that Marcellus production comes back up, I guess, about 100 million a day. And I guess it’s averaging in that 2.2 range versus 2.3 last year. Can you talk about the considerations of inventory management and how that mix of lower versus upper, is looking over time? It seems like there’s a multiyear shift now where you’re going to be emphasizing the lower a bit more in the lower price environment. But just wondering if there’s more nuance to it and if your thoughts have changed on the inventory management side there?
Tom Jorden: Our thoughts really haven’t changed. As we were — I would just repeat what we’ve said in the past. We’ve talked about a reduced inventory in the lower Marcellus. I think, if we were heavy on the lower Marcellus, we’d probably be talking about a three-year to five-year inventory at this point, three-year to six-year maybe, depending on our level of activity. Our inventory is longer than that now as we’ve lowered our investment. But it’s really a function of what’s available to us and that’s the function of our gathering system where we think we have additional capacity. But there’s also an area of this field that’s opened up to us that we’re out exploiting and we’re really glad to be there and getting after some of the really, really productive rock.
So, we’ll be drilling in the lower Marcellus for a long, long time. So when we quote inventory numbers, it’s really strongly overprint by which formation we’re drilling in. But the lower is going to be a significant part of our program for a number of years.
David Deckelbaum: Thanks to the color there. I’m also curious on the Permian, embedded in this multiyear 5%-plus oil growth outlook through 2026. How many sort of projects similar to the size of Windham Row are you baking in, I guess, per year? I know that there was an expectation that we would see sort of a large-scale project every year and a half. Is that still kind of the cadence for the multiyear guide or are there some early learnings from Windham Row that are kind of iterating that process now?
Blake Sirgo: Yeah, David. This is Blake. I’ll take that one. Right now we really expect to do a row project almost every single year. And I know that it’s kind of scary to talk about a 51-well development, but I think it’s important to remember these are six distinct drill spacing units that we have chosen to develop in a row to maximize efficiency. These units are our standard Culberson 2-mile Upper Wolfcamp units with designs from seven to 10 wells per section. This is just really our bread and butter. I mean, we’ve developed many of these over the years. We’re just stringing them together. Our ops teams work really hard to kind of war game these projects and these rows to think of all the execution risks that could go on.
That’s why we picked up our eighth rig sooner, to get a good duct build in front of the frac crew. These projects have large multi-well pads. That means if we have any well trouble, our frac crew can pivot while we deal with the well trouble. Our simul-frac part of this project, we’ve modeled really conservative completion timing and that’s because, it’s our first application of this in Culberson, but we don’t really expect our electric crew to operate any less efficient than it has in the past. We worked through a lot of sand and water logistics to make sure everything has abundant sourcing. We own and operate our SWD system out there. That means we have plenty of water on demand at all times. It allows us to keep it in the pipe, so we’re not building any produced water pits with this project.
This is just part of our operation now and I’d expect many more row developments for years to come.
Operator: Your next question comes from the line of Neal Dingmann with Truist. Please go ahead.
Neal Dingmann: Good morning, guys. Thanks for the time. My first question is just on the flat span and the zero percent to 5% Boe CAGR. I’m just wondering, did these assumptions include, I’m just wondering, do you assume with those on a go forward years, has that ensued well productivity, improved well productivity, lower well cost, or maybe just help me on what’s involved in those assumptions?
Tom Jorden: We don’t project future advancements in advance of having achieved them. I think we will achieve them, but we don’t — we like to calibrate results. I mean, hopefully that’s not a surprise to anybody on this call. We’d much rather talk about results than promises. And I just want to say one more time, we don’t manage our multiyear outlook by that production number. We look at projections of what we think is our assumed cash flow. We say how much of that cash flow do we want to invest and that’s typically in a fair way. I’m going to give a wide one of 40% to 70%, and that allows us to achieve our shareholder returns that we’ve promised. And then with that, we say, okay, here’s the capital, where’s the best place to put it and the very last part of that process is what production does it generate.
