Certainly, it’s fun to talk about the records, but really in order to be successful, we know it’s important that we be repeatable. So, how do you translate that then into repeatable format? We think that has the opportunity to further improve our overall breakeven cost from that inventory bidding perspective.
Doug Leggate: Hey, Dennis …
Mark Scucchi: Good morning, Doug, this is Mark. I’ll …
Doug Leggate: Yes, sorry to interrupt. I’m at the corporate level, the corporate level, not the well level. Sorry, Mark, go ahead.
Mark Scucchi: Sure. I think stepping back and look at the corporate level cash flow, third quarter this year is really an exemplary example of what this asset can do. We generated greater than $90 million in free cash flow. We intentionally reinvested and deployed that, maintained the balance sheet strength, pay the dividend, continued to maintain and improve the balance sheet because this asset in one sense can be viewed like an annuity. I know that’s one lens which you use to value a company is we fast forward and look at what this company can do. There’s a few scenarios in our deck to talk about free cash flow hypothetical scenarios. As we approach $4, you’re generating what we think is a reasonable, perhaps conservative estimate of $1 billion per year corporate level of free cash flow and greater.
And I think it’s notable also that that incorporates an assumption, a fairly conservative NGL realization. So, there’s basically an option, an upside option embedded in that as well. So, if we’re thinking about a maintenance scenario, that represents an enormous annuity of cash flow range. As we’ve talked about before, and as Dennis has already said, we are very mindful of positioning the business to be resilient if prices are soft, but also to position ourselves to participate in growing demand, whether that’s 2025, pick your timeframe, Range has the capacity, the willingness, and the ability to grow efficiently and generate what we think will be some of the most competitive margins out there. So, I think the repeatability of that also to Dennis’ point is key.
This inventory depth, multiply that out across a couple decades times $1 billion of free cash flow annually at the corporate level and improving as we pay off debt and other corporate costs reduce on an MCFE basis, expanding your per unit margin, that I think really does represent a unique opportunity in this space.
Doug Leggate: Mark, thanks for the clarification, guys. You’re right. I mean, I don’t think too many companies can claim the inventory depth, so I don’t know whether I’d say we look at everything in as annuity, but it’s certainly inventory depth is a big constraint on valuation for sure. So, thank you for that clarification. Quick follow up guys. If your inventory depth is defined on 10,000 foot laterals, which I believe it is, but you’re drilling significantly longer laterals and improving capital efficiency, how much longer do you think – I mean, how long do you think the program can continue to step up into those longer laterals? And I guess what’s the inventory for the longer lateral, is the question, so, and I’ll leave it there. Thank you.
Dennis Degner: Yes, thank you Doug. I think there’s a lot of running room when you think about the ability to further extend our laterals and what that means to our overall program. If you look back over the past, let’s just say three years, I’ll pick something reasonably near term, year-over-year, we’ve seen a continued theme of incrementally increasing our overall lateral links. And I know we’ve talked about this on previous calls, but also while returning to pad sites with the existing production. So, this isn’t necessarily what we would call clean sheet development where you’re moving out into the fringes of your asset base. This is in and around prior producing wells and taking the learnings from those historical executions and translating that into more efficient execution and planning.
So, we see the 21,000-foot laterals that we drilled this year as a good reflection of that. We’ve got in excess of 60 wells that are at 15,000 foot in horizontal lengths. So, again, we’ll move methodically through equipment upgrades, procedures, KPI tracking and make sure that we’re extending our laterals in the most efficient and prudent way. And look, at the end of the day, we’ve got an inventory runway, even with extending of these laterals, that’s greater than 30 years, with breakevens that are in the $2 range or better. And so, we think this is going to bode well as we think about the runway of this inventory development process.
Doug Leggate: Gentlemen, thanks for your time. Appreciate the answers.
Operator: And one moment for our next question. And our next question will go me from Jean Ann Salisbury of Bernstein. Your line is open, Jean.
Jean Ann Salisbury: Hi. good morning. One more follow-up on the drivers of the longer laterals and fewer turned in line wells. How material is the shape of the forward curve in that decision? For example, if the forward curve goes into backwardation, would that kind of push you to stop extending lateral length or even potentially go to shorter laterals?
Mark Scucchi: I think maybe from an economic standpoint, I’ll start this one off, the shape of the forward curve won’t drive – won’t be the primary driver in that decision making process. As we look at efficiency and driving the lowest maintenance capital number possible, it is optimizing those capital reinvestments. It is creating a company with a, call it 40% or better reinvestment rate to hold production flat, and that $0.70 some per MCFE capital expenditure to hold production flat. So, the shape of the curve, as we think about the overall economics, it’s also impacted by the flat decline rate that Range had, that 19% of decline rate. So, as you flatten that out over time, we’re looking at a price three years through the seasonality, what the sustainable price levels are, and of course, that’s also bolstered by the hedging program.
So, prices will move. They will move erratically. Our balanced program that generates significant contribution from the liquids cut as well, combined with the natural gas cut, along with sales points across the US. The shape of the curve doesn’t necessarily impact us deciding to drill a 12,000 to a 15,000 foot lateral. Really, it comes back to, what’s the economics? What’s the space in the existing system? Where are we placing that to optimize the use of the existing surface facilities, existing compression, gathering and long-haul transport. So, not to talk around the question, but it’s just a multifaceted equation and evaluation we do to make sure we can get the most out of each reinvested dollar.
Jean Ann Salisbury: Yes, no, that makes sense. Thank you. And then your differential guidance for the year moved – it was slight, but moved slightly to the $0.40 to $0.45. Can you give any more color around whether that was specific in markets getting a little bit worse or in basin pricing?
Mark Scucchi: Laith can add some details to that, but I think the short version is, we all know in shoulder seasons and where storage levels were in the third quarter, there were some soft spots in the in-basin markets, in particular in Appalachia, but fortunately, 80 plus percent of our gas is out of basin, and basically all of our liquids, over 90% of our revenue is out of basin. So, that’s a reflection of that minority of the production that’s sold in basin. It is bolstered by a basis hedging program, and effectively a basis hedging program embedded within the physical sales and diversity of customers we have. But that’s the long and short of it. There’s been no substantial change to our portfolio of customers. We still sell across greater than 30 different natural gas pricing points, and we’ll look to keep optimizing that program over time, that portfolio over time.
Jean Ann Salisbury: Great. Thanks. That’s all for me.
Operator: And one moment for our next question. Our next question will be coming from Umang Choudhary of Goldman Sachs & Company. Your line’s open.
