Concho Resources (ticker: CXO) now running 32 rigs
Q: When I’m looking at the various kind of sizes of the projects, anywhere from kind of 5-well pads to 20-well pads. And you all do mention in the slides that, for example, on the Dominator pad like you all had to basically coordinate over a year in advance with the midstream partners with that project. I’m just kind of curious how much kind of the midstream component has an impact on the size of these kind of pads? And then, kind of longer term, if we should sort of think that these projects are likely going to kind of gravitate toward the larger end of that range over time?
CXO: I mean, midstream is certainly one of the elements that goes into sizing it. But I would say the bigger driver is – well, let me step back for a minute. I think we’ve been one of the leaders in moving to these larger-scale development projects. And that’s been a steady evolution over the last couple of years as we’ve tested different spacing between – within a zone and between zones. And so, these bigger and bigger projects I think are just the further evolution of that trend. Where you see some of the smaller projects, that’s us continuing to test tighter spacing or different spacing within a zone or between zones again. And so, I think you’re right, longer term, you’ll see an evolution to the bigger and bigger projects. However, we’re still learning as we go and so I think you’ll see a blend of different sizes.
Q: Congratulations on getting the RSP deal completed. Looking at the rig count that you’ve ramped up to combined for the two companies at 32, you’ve added about 5 since the deal was announced. And 4 of those 5 are on the Concho properties, which at 24 rigs is a little bit higher pace than what you’d originally planned for the year. Could you just talk a little bit about the acceleration now on legacy Concho assets and why you’re seeing more acceleration there at this stage as opposed to RSP deal? So just overall the acceleration activity, if that’s driven by oil prices or just the better positioning of the combined companies?
CXO: I’d say that what we’re doing on the Concho properties is consistent with what our plan had been for the year. We did add those rigs here over the last month or two, but we’ve also added a rig to the RSP properties. And like I said, at this point, it really just reflects what the two companies were doing on a stand-alone basis and I think you’ll see – you’re starting to see it now that we’ve closed and over the course of this year, you’ll continue to see us I think put our stamp on those properties. But I wouldn’t really characterize that as anything different than what you should have expected earlier in the year.
Q: I kind of feel as if I ask you this question every quarter, but for the combined company you’re – well, on a standalone basis in Q2, you generated free cash flow. And the combined company in this commodity deck, it looks like that might continue even at a higher activity level.
How should we think about your prior comments about spending cash flow? And I think a couple of quarters ago, you talked about when you do something, it will be significant as it relates to surplus cash, whether it be dividend or buyback or something. But can you just frame your thoughts if post the Permian bottlenecks, oil prices, let’s assume, hold up at this new trading range we’ve seen recently?
CXO: Yeah. Well, I think one of the most important things to start with is that these capital programs we put together are the highest rate of return capital efficient programs we’ve ever had in the company’s history. So, a lot of our cash flow goes back into those programs because they create so much value. I would say over the longer term, though – and going into the next year or two, oil prices have been very volatile and we’ve been pretty conservative on how we build our capital program and what commodity price we look at for that program to breakeven.
I like the notion of generating free cash flow and growing dramatically. And so I think in the short-term, you’re going to see us generating free cash flow and growing dramatically. And then, beyond 2020, I think as we’ve discussed in the past, we have all the options in front of us on what’s the best way to create value for our shareholders, what’s the optimal rate to run our machine. And I think we’re just going to be really well-positioned.
Q: Really just wanted to get your take, kind of at a high level, of how you see the dynamics playing out in the Permian over the next six or 12 months. Jack mentioned in his prepared remarks that production has really exceeded expectations. And as we kind of near pipeline capacity, just really curious on how you see the potential for differentials to vary? What dynamics you could see ultimately happen with producers, certain behavior, et cetera? Just really your kind of high level thoughts. Thanks.
CXO: Well, let me start with the high-level thoughts. And we have not had any problem moving or selling our crude oil. And historically, we’ve seen situations like this before where it was just two years ago that everyone was asking about access to service and supply and it came along big time for us. So, the Permian is a great place to be. Transportation resources out of the Permian I think will supply all the needs the industry has. And I think that my expectation is, from a very high level, that when there is a need and there is economics involved, that our industry is great at responding to that need.
So, I think that we’ve seen these blowouts in differentials before, that’s why we have the type of hedging program we have. I think it’s probably – this problem will be solved more quickly than anybody’s estimating. And then we’ll be on to the next problem.
Noble Energy (ticker: NBL) driven away from the Permian by differentials
Q: With regards to the Permian, as you defer completions there, when do you bring that backlog down? And what would you need to see to allocate either more or less capital out of the Permian, into the Permian, and out of and into the DJ?
NBL: Well, as far as allocating more back into the Permian again, obviously, it’s going to be tied to that export capacity coming on. That’s why we are shifting it out, to give the system time to grow the capacity to be able to deliver the wells that we’d actually be drilling and completing. So, assuming the projects stay on track, those capacity expansions stay on track, then we would expect to start adding frac crews back into the Permian relatively early next year. I’m sorry, what was the first part of the question?
Q: Well, I think you got the first part, but what would you allocate more capital to, to the DJ as well?
NBL: I think as we’ve mentioned, the capital that we’re – or the activity that we’re taking out of the Permian this year is going to the DJ. We’ve obviously ramped up in the Mustang IDP. Again having those three gas outlets gives us the confidence that we’ll be able to move the gas. The early results we’re seeing on those Mustang wells are very encouraging. We’ve seen tubing pressures that are significantly above similar GOR areas in Wells Ranch. And so, it’s very early days. We just brought them on here in the last few weeks, but everything we’re seeing is very encouraging.
So, the projects are there. The economics are certainly there in the DJ. We believe the takeaway constraints in the DJ on the processing side are finally being addressed. And so, there is not a lack of opportunity in the DJ. It’s going to go back to, again, the overall mix of the portfolio, the economics of the portfolio and how much capital we’re going to be deploying at any one time.
Q: I was hoping to drill a little bit further into the Permian here. Clearly, you guys are pulling back activity. Is that going to be both drilling and frac related? Do you really plan back on completions in the fourth quarter here. Just trying to get a sense, though of how that impacts the production ramp. Is Permian still going to be growing despite the activity pullbacks? Is it just growing in a lower rate?
NBL: Permian will still be growing. It will be growing at a little bit lower rate here in the near term, given the deferral of completions, while we are waiting for the export capacity to come up. I think when you look at it, the way we’re thinking about it right now is we probably lay down two of our three frac crews late in the third quarter. And assuming that the capacity build-out continues as expected, we would start adding those back pretty early next year.
Right now, we’re planning on maintaining the six rigs. We’ll continue to take a look at that as we go through the year. But maintaining that level of drilling and building the inventory of completions and building the buffers that you need as far as the row style development goes, we think maintaining the six rigs is the right way to go. That will result in a slight increase in DUC inventory near term until the completion crews come back. But we’ve modeled it and looked at it economically, and we believe that’s the right thing to do.
Southwestern Energy (ticker: SWN) Fayetteville recompletions experience may one day be applied to Appalachian position
Q: After you have your water system in place, where do you expect well cost to be in Appalachia by liquids rich versus your more condensate area or dry areas?
SWN: Sure. That all will vary dependent upon lateral length, but when we get those – both of those water systems fully up and running, and we’ve talked about the $400,000 per well benefit in Northeast App, and a $500,000 per well benefit in Southwest, we feel comfortable we’ll get down in that $900 per foot type of range on the performance of those wells.
Q: Say, I just was curious about the redevelopment results you had in the Fayetteville and just wondering if you had any sense of what the returns are on projects like that. And I was also wondering with the legacy development pattern, are sort of all vintages of wells in the plate equally good candidates for redevelopment or does it sort of depend on when they were drilled, how they were completed?
SWN: There’s a lot of them that are, all benefit from the latest completion and latest landing zone technology. If you remember, there’s a mix of wells that are DUCs on our books that we’re drilling now with the current technology and then there are wells that are offsetting existing producers. And the one that maybe has a little more variability that we look at is when, how they were completed, what vintage of well they were, how long the lateral was, how much of it stayed in the zone. But using the data analytics that we have for that area, we’re able to high-grade those opportunities.
Q: I wanted to go back to the question about the Fayetteville recompletions again and just to ask you two things. One, as you continue to manage the decline in the Fayetteville until you reach the end of your process, are you mainly doing recompletions to optimize the decline rate or are you still doing some active drilling in the Fayetteville?
SWN: The wells that Clay talks about and redevelopment are all part of a test program. While we own assets or own anything we constantly are working on them to improve them. But the capital program for SWN under our capital allocation model of highest PVI and economic returns focuses the vast majority of our capital to our Appalachia Basin area, and that’s where our focus is.
But really any changes in decline rates or any or activity around gas in the Fayetteville is because of the work the teams are doing to continuously operate and improve that asset on an ongoing basis.
Q: And a follow-up to that is just, some of these things that you’re learning in that program in the Fayetteville, would they be eventually applicable to Appalachia legacy portion, so whenever it’s appropriate to take a look at that at some point in the future?
SWN: Absolutely. And we have, one of the great things we’re doing is we’ve really accelerated the learning cycle. So as we try an opportunity in one part of our company and we apply it in the rest. So we’re already in the planning stages around doing some of that and we’ll bring that information out shortly. But both parts of the Appalachian division have opportunities there.
Q: For several years now, you have more or less invested largely within cash flows. You were one of the earlier companies to do so. And I was just wondering, what are your thoughts on potentially breaking glass in 2019 or 2020 and transitioning to just keeping production flat year-on-year, but just producing a significant amount of free cash flow that could be used either to apply it to the balance sheet or to pay some sort of variable dividend? Just trying to get your thoughts on a potential shift in the strategy longer term.
SWN: And I think when we look at the 2019 plan, the context around it always needs to be, first, invest within cash flow and then look to optimize value; not investing outside of cash flow, but at what rate do we invest, do we, what do the commodity prices look like, and as a public company, you’ve got to look at options like that.
Do we continue to drill at the pace we are? Do we slow back down? Do we put cash to pay further down our debt? So I think your question has more than just those three options to it and we’ll look at all of them, too, as we put the plan together.
