Neal Dingmann: Good morning, all. My question is on your Marcellus G&P, specifically number of E&Ps, I haven’t heard too much from them as far as plan for any change of activity but yet I did hear from a flag provider last week that suggested that you could see some slowdown in fracking activity for the next few months or a bit longer in Appalachia. So I would just love to hear, I did know you’re — looking at Slide 7, it was down a little bit, not a whole lot there versus the year-over-year. So I’m just curious more on your overall thoughts in the area for the remainder of the year.
Greg Floerke: Neal, this is Greg. At this point, we still — we’re in close communication with producer customers and we track over time well pads that are being drilled and completion rates. And depending on rig availability, depending on weather, depending on pricing, those things, obviously, those forecasts can and do change. But we still — as I mentioned before, a lot of the activity in the volume drive that we forecast into ’23 is based on activity, drilling activity in ’22 and then some completion activity that already has been underway. So there could be pads delayed, not aware of those, but that’s always a possibility. But at this point, we still feel bullish about volume this year.
Neal Dingmann: Yes, I agree. Go ahead, Mike. Sorry.
Mike Hennigan: Yes. Let me just add, even outside of the Marcellus, I think everybody realizes now there’s a structural change in gas from a lot of perspective. So in some of the areas that had not seen a lot of activity, as Greg mentioned earlier, in ’22, you’re starting to see rigs in other basins outside of the Marcellus that haven’t had a lot of activity. So I think overall, people are recognizing a structural change in gas now. Very short term, it’s been a little warm relative to expectation coming into the winter. But if you pull back up to a higher level of structural change, more activity, rigs being used in basins that there has not been activity for a while, I think shows that there’s a change in gas potential going forward.
Neal Dingmann: Yes. Well said, Mike. And then one just clarification, I want to make sure on the gathering, you continue to have nice increase on the gather on the other side, non-Marcellus. Shawn, can you remind me of just capacity? I still think you have a bit there on the Permian at all. I’m just wondering again what is — I think you talked about this earlier today. I just want to make clear on what is still the capacity available on the gathering side there.
Shawn Lyon: In terms of the Permian Delaware, the capacity, we basically build out and connect new wells and add compression as we need it to fill the processing capacity that we have.
John Quaid: Neal, it’s John. Specifically in the Permian, if that’s what you’re asking about, right, we’ve got our five plants, we’re building our sixth. They’re each about 200 million a day. So that’s the size and scale of that operation, which, in our numbers, it’s part of the Southwest region that we show. We’re at a B heading to 1.2B. And we match the gathering which I believe you specifically asked for to that capacity.
Neal Dingmann: That’s right. Okay. Thanks, guys. Great details.
Operator: Thank you. Our next question will come from Spiro Dounis with Citi. Your line is open.
Spiro Dounis: Thanks, operator. Good morning, team. Wanted to go back and follow up on one of Brian’s questions just as we think about refinery run rates for ’23. And if we zoom out a bit and just look at the industry as a whole, I believe it’s supposed to be kind of a heavier refinery maintenance year this year. So curious how you’re all thinking about the impact to your system overall, whether or not that ship flows on the export side or internally, just curious how you’re thinking about the net benefit or negative there?
