Arun Jayaram : Thanks Alan.
Alan Farquharson : You bet.
Jeff Ventura: And slide five kind of is a new slide with more of that color in detail that Alan was referred to in the deck.
Operator: We are nearing the end of today’s conference. We will go to David Deckelbaum of Cowen for our final question. Your line is now open.
David Deckelbaum : Thank you. Can you hear me?
Operator: Yes, we can hear you.
Jeff Ventura: Yep.
David Deckelbaum : Thank you. Thanks for squeezing me in. I just wanted to ask about the lateral length progression ï¬rst. It sounds like 2022 was kind of like a landmark year in terms of average lateral length. Obviously, the tilt count goes up a bit in ’23 as lateral lengths comes down. It seems like there’s still some potential to increase that throughout the year. How does that look when you get beyond ’23, into the ’24 and ’25? Or should we see the program kind of conforming towards this 10,000 foot kind of standardized lateral that you have assumed in long term costs?
Mark Scucchi: Yeah. Good morning, David. You know I would say as we look forward, we have yet to experience the technical limit of our horizontal lateral capacity. But we also take a very methodical data driven approach to how we extend laterals, because I know you’ve heard us talk about this on prior calls, but in order to be successful, we know we need to be repeatable. And so making big leaps is something that we’re not opposed to doing, but we try and incrementally extend our lateral lengths and operationally take those learning’s so that we can do it in a very cost way effective way. We can also be very repeatable. I think if you look back over the last couple of years, as you point out, we continue to make a progression to €“ as we just touched on in our prepared remarks, we drilled some of our top 15 longest laterals in the balance of the fourth quarter, and we have more wells like that planned for the 2023 program.
As we look at our €“ internally, our five year plan and outlook of well inventory, where we would be bridged to gathering system and how that would complement that activity level, there are lots of wells that we would consider to be at or beyond that 15,000 foot level. But as you move throughout the ï¬eld, there will be cases where you maybe have some lease limitations that would prevent you from always drilling in excess of 15,000 feet or which then creates more of an average of 10,000. We know that our long laterals create our most capital efficient opportunity. So we see a really, really long runway with our inventory to be able to drill extended reach laterals, and we’ll continue to do so.
David Deckelbaum : Thank you. And then as my second question, this is Jeff, maybe to close out the call on something a little bit more exciting. Just it sounds like you conï¬rmed that perhaps there were not conversations around M&A last week. But longer term, does the Board or management believe that there is perhaps a philosophical goal of getting towards perhaps some sort of combination with an oil weighted company to create a differentiated investment proposition as an organization? Or given your constructive view on gas macro, do you think your best path forward is to focus on core natural gas development in the U.S.?
Jeff Ventura: To answer that, I would just say we’re really in a great position. We have what we believe is the largest core inventory and the best gas ï¬eld in the world. Big blocky position, you know we have the new disclosure on page five or whatever talking about the quality of the wells and the longevity. We’ve got the lowest decline rate. We’ve got the lowest cost structure into what we think is going to be a much better natural gas story long term. I think natural gas is going to be a great place to be. We think, and there’s a slide in the back, you know LNG, we talked about the next wave, big wave in 2025. Dennis says it starts in 2024, but when you look at our slide in the back, we see that by the end of ’27, LNG exports 29 Bcf per day, and there’s a slide in there and that describes them.
