Chris Wright: I’ll take that one, Keith. So it will probably be about half of the gas usage. We’re going to focus very specifically on the places where you’ve got 100% downtime, right? So the digiFleets. The digiFleets you need, when you don’t get gas, you don’t have steady gas, those fleets aren’t working, right? So the number one focus is making sure, we support the 100% gas fleets and then moving to more of our high usage Tier 4 fleets. So, I’d say about 50% of our gas users will probably be covered by LPI by the end of the year, Ron of course?
Ron Gusek: I think that’s a good number.
Chris Wright: So I think you’d see even with the lot of growth this year with LPI there’s still a lot of Liberty fleets and gas consumptions still not covered by that. And that’s just within that original application. So we got lot of room.
Keith MacKey: Got it. Got it. No, that makes sense. And just going to the digiFrac versus digiPrime, can you maybe just discuss a little bit more of the factors that are leading you and customers to choose one versus the other? Is it upfront capital? Is it efficiency? Is it where the equipment ultimately goes in the field? Just a little bit more color on your thinking would be helpful on that.
Michael Stock: Yes, Keith. So for both of those, they offer the advantage of that transition to natural gas. So whether we choose to use it for power generation and then an electric pump or in digiPrime’s case directly for running a pump, they both offer customers that important transition. Where you really start to think about where we might apply one versus the other comes down to whether or not the customer believes they would have access to grid power, for example. So did you frac, we have the ability to take power from any source. It’s agnostic as to where that electricity comes from, primarily, that would be generated on location by us. But we have a number of scenarios where customers have asked about the opportunity to use some amount of grid power or potentially even ultimately all grid power to run a frac fleet.
And so in that case, that’s going to be 100% digiFrac solution. In a scenario where we don’t have that environment where the primary driver is just the consumption of natural gas, you’re probably going to see digiPrime as the first choice that we would put out on one of those locations. We get a little bit better thermal efficiency and just modestly lower emissions footprint as a result of removing that conversion from mechanical to electrical and back to mechanical again. You’ll see digiFrac on top of that or Tier 4 DGB one of those two as they are, we’ll call it the peaker plant on top of that to absorb just the ebbs and flows of frac to ride the line on pressure or whatever the case might be. But digiPrime being the workhorse in that sort of environment.
Keith MacKey: Okay. Thanks very much.
Operator: And the next question from Dan Kutz with Morgan Stanley.
Dan Kutz: Hey, thanks. Good morning. Maybe, Michael, just thinking about free cash conversion for this year. So, you gave us the CapEx guide and that kind of represents 45% of the adjusted EBITDA guide you gave us some figures around cash taxes, which my scratch math kind of says might be 10% of adjusted EBITDA and then you kind of have some cash interest and maybe stock comp offsetting each other. So ex-working capital, do you think 40% to 50% free cash conversion? Is that in the right ballpark? And then secondarily, do you have any thoughts on whether working capital might be neutral, positive, negative this year? Thanks.
Michael Stock: Yes. I’m get some scratch math. You’re running that and have those numbers prepped in front of me as a percentage of EBITDA. But working capital, I think, is going to be basically flat. We’re talking revenues base. I mean our working capital kind of moves with revenue. So, I think working capital is going to be basically flat. We’re talking about cash taxes, as we said, in the time about a 20% range, as you say, interest and EBITDA offsetting each other, you got depreciation. Yes, we’ll get back to you. I do the math. I don’t want to throw it out on the call.
Dan Kutz: Fair enough. And then maybe, Chris, you mentioned earlier a comment about kind of needing more activity just to offset production declines. I was wondering if you’ve done any work or could unpack that, like do you think that we’re kind of below where we need to be for both oil and gas activity to offset production declines. Do you think publics or privates are kind of below where they would need to be from an activity perspective to hold production flatter or maybe grow a little bit. I’m just wondering if you could unpack the comment about activity as it relates to the production.
Chris Wright: Yes. I wish I had a more confident comment, because we do some bottom-up analysis and productivity and where we’re going. But honestly, we were also probably a bit surprised by the rate of growth last year, given that activity. And I think the most likely reason is a larger percent of that activity was from sizable publics that have the best acreage. So the quality of locations drilled, which is generally trending downward, people drill their best uppers and move out. But as you saw, a shrinkage of private activity last year and a growth actually among the activity among the public’s that have the very best drilling locations that probably was the biggest factor a bit in the surprise for how fast oil and gas production grew.
But we’ve got to go through our data. So, I don’t have any great confident proclamation there. My guess is current – certainly, on a granular level, we’re working for players that are at activity levels now that are definitely declining production, others that are modest growth and others that are flat. But like that is where we are today in total activity, you won’t see that until summer production data. We’re probably at fast flat in the sum of oil and gas production. So yes, I don’t think activity drops much from where it is here. It’s more likely to move up a little bit as the year goes on to stay around modest growth, which I think is the target.
Dan Kutz: No, that’s all super helpful. Appreciate the color and I’ll turn it back. Thanks.
Chris Wright: Thanks.
Operator: Our next question is from Saurabh Pant with Bank of America.
Saurabh Pant: Hi, good morning team. I had a question. I think Derek asked this early on efficiencies. If I want to take that forward and just talk big picture, we always tend to talk about the ratio between rig count and frac fleets. Any thoughts on how much room there is to keep improving efficiencies? And if that can have a potentially meaningful impact in terms of where that ratio goes. And the reason I ask that for context is one big E&P had an event in the Midland, I think, last week, and they were talking along those lines. So curious to get your thoughts on that.
Chris Wright: Yes. We saw that note, and there’s going to be a whole new ratio now. And so look, I think it’s important to – you had to step back and put those in context. When you’re doing simul-frac or trimul-frac, that’s not one frac fleet, it’s pumping, right? That’s a trimul-frac might not be three frac fleets, it might be 2.4 frac fleets or something. But that’s for horsepower for equipment, you have more equipment on location when you go to those larger operations. So in frac fleet size that are doing things like that, we don’t view that as one frac fleet if we’re doing something like that. That’s more capital equipment. And we look at returns, not on fleets but on capital investment. So there are efficiencies, and if you’ve got a perfect supply chain, large pads and you’re willing to put capital out a long time, there is activity like that going on.
