And as far as being adapted to prices, we’ve also got a good base set of hedges that further inflate cash flow and provide us a greater predictability, near and medium term. And then of course we’ll be responsive to any severe moves. We clearly are not going to look away from prices and realities of realized netbacks. But all that being said, under virtually any reasonable pricing scenario, we’ve got a variety of scenarios down to $2, $2.50 for example on page seven of our deck. Range is generating extremely competitive levels of free cash flow. So we feel good about the program and don’t expect there to be any material alteration. That said, we remain nimble and will adapt as need be.
Paul Diamond: Understood. Thanks for the charity guys.
Jeff Ventura: Thank you.
Operator: Please stand by for our next question. Our next question comes from the line of Neal Dingmann of Truist Securities. Your line is now open.
Neal Dingmann: Good money, all. Thanks for time. Hope you can hear me a little bit loud here. My question is on oil field services. I’m just wondering, you have seen a bit of a decline now in some of the gas areas like here, so I’m just wondering, has that shown through on maybe not rigs yet, but maybe some of the other oilfield services or is it may be still too early to tell.
Jeff Ventura: Yes, thanks for the question Neal. I’d say it’s a little bit early. I think for those service cost reductions to at this point fully surfaced. But again, I kind of tried to touch on this just a little bit earlier. The good news is we’re not seeing any further requests for increase at this time. We’ve seen in some ways a good strong stabilization of the service cost market. But we fully expect as rigs fully materialize and being dropped in the months ahead, and we start to get deeper into the year, there to be further opportunities for us to evaluate service cost reduction opportunities. And I’ll throw this on. I mean we also €“ you know service cost is always one component of our cost structure, but our efficiencies are the other.
As we look at how we are attacking the program this year, we would further expect to repeat our efficiencies and continue to build upon them, further reducing that cost structure. So as you kind of dial all this back, we kind of feel like at the end of the day and Mark just touched on it this morning as well in his remarks. But we expect regardless of the outcome to be at the leading edge of what that dollar per M efficiency value looks like at that 76 level.
Neal Dingmann: Okay, to my point and I had one follow up. Just Dennis, I think you and Jeff talked about this, but on the additional inventory you see for the next year or two, is most of that €“ will that be the longer laterals or can you just maybe talk a little color on the type of wells you anticipate? There seems like they’ll €“ it seems like you’re you could see a bit bigger, better margins on that type. I was just wondering, was that because of the long potential laterals or is there more things to that?
Jeff Ventura: Yes, as we think about the inventory that we’re adding this year, it’s really to do a couple of things. One, it allows us to have some optionality as we think about 2024 and 2025, but you should really take a step back. We’re really talking about adding somewhere between one to two pads sites of wells in wellbores. And so again, that’s going to allow us to further operationally de-risk the program, not only maintain our current efficiency levels, but also to build upon them. And as we kind of look at the drilling efficiencies and records that the team set already in 2023, by having some of those efficiencies that we’re already capturing, plus completion efficiency improvements from last year, you can see some of that activity then further making it into this year’s program.
