Chesapeake Energy's (CHK) Presents at Bank of America Merrill Lynch 2017 Global Energy Conference (Transcript)

Chesapeake Energy Corp. (NASDAQ:CHK) Bank of America Merrill Lynch 2017 Global Energy Conference November 16, 2017 2:50 PM ET

Executives

Jason Pigott - EVP of Operations and Technical

Analysts

Unidentified Company Representative

Up next, we are very fortunate to have Jason Pigott, Executive VP of Operations and Technical from Chesapeake Energy. We will start with the presentation and then we’ll open up for Q&A.

Jason, with that out of the way, I’ll leave it to you.

Jason Pigott

All right, sounds great. Thank you for having us today. Again, we’re really excited to tell you about the Chesapeake story. We are doing something a little bit different than we’ve done traditionally at these conferences. I’ve got with my team some of the guys from the big data team that can also -- because that’s been a big focus for us as a company.

Now, before I get going, I just need to kind of go over our mandatory disclosure statement that we’ve got some forward-looking statements that we will be discussing today. But then, we’ll go in quickly over the priorities of the Company. These are things that haven’t changed for us, again, what Chesapeake has been focused since I came on board and Doug as well with financial discipline, business development, growing efficiently from our assets as well as exploration.

As we look to our priorities for 2018, we’ve highlighted some of these before and they still remain front and center for us and that is getting to cash flow neutrality. And we’ve been hampered a little bit by $50 oil instead of $60 oil, but still a top priority for us. We also want to retain some posture for growth. We’ve got great assets. Our productivity is increasing just every single day, which I’ll highlight to you today. And then, front and foremost is this focus on getting the $2 billion to $3 billion of debt taken off of books.

I am pleased to announce this week, we actually had a divestiture in our Mid-Continent that brought in a $170 million, and we only had to sell 23,000 acres to get there. And if you looked at our EBITDA that we lost, it’s minimal for this. It’s only 300 barrels of oil. So, we are continuing to chip away at this $2 billion to $3 billion target. If we look at 2018 year-to-date, inclusive of this divestiture, it’s $535 million and the EBITDA from those wells next year was only $23 million.

So, when we think about transactions that are accretive to the Company, we are really starting to make those. Our eyes are on the bigger pride and getting some larger chunks of that taken out. But we’ve been very creative with doing some of these non-core divestitures that are non-material to the Company and ultimately additive to us.

And then, our final focus for the next year again is just keeping some portfolio optionality. We are continuing to explore. We have got a great story in Powder that’s developing as we are testing new formations but we also have great things going on in our other core assets with great Austin Chalk wells and the Eagle Ford, Marcellus Upper test, and we’re going to even test at Utica in 2018, and Marcellus as well. So, great story there.

A little bit about myself. I came into this role, new role, I am with [ph] Chesapeake four years now but transitioned to a new role, which is this Operations and Technical Services role, which is a really long title, but it’s got a lot of cool things that I report up into it. So, we’ve got drilling, completions, our infrastructure services, which is the facilities, land, op services, which is our continuous monitoring, supply chain. One of the ones I’m most excited about is the integration of information technology with operations. So, reporting to me, we’ve got well construction plus IT. IT formerly reported into the finance organization. And I think what we’re starting to really see is when IT and operations are combined together, we’re getting these transformational changes in our assets. This diagram on the right chart is the highlight, like how we’re able to pull this information together today, unlike we ever have been for. We can pull in our drilling data, completions data, the production data, the finance, the marketing data all into one pool of information. Then we have these, our big data analytics, the process and crunch, and ultimately drive value for the Company.

So, I’ll describe for you a little bit about our big data journey as a company. We started this a while back in 2005. At the core of it was field automation. We have bit [ph] sensors on all of our wells in Chesapeake that can basically afford this. So, we’ve got auto, tank level sensors, pressure, rate, data, separator pressure, this all data that streams in today, but we were early on set up our wells with automation. We also created a reservoir technology center. Again, we’ve got a great core lab there that also helps when you’re trying to create a new play from scratch, like the powder and how different formations. We can take those cores and have them analyzed of the fly. Also, as we look to create reservoir simulations and time, what we’re doing on the completions front with our rock data, we can just go take a core plug, run some new rock mechanics et cetera. So, that drives it for us.

The tile at the top, I think is important too, because what is big data, it means different things to different people. So, when we go to well automation, we’ve got a high volume of data that we are able to process. The next phase of big data for us was this velocity. And that’s when data is streaming into line. [Ph] We created in 2012, a drilling operations center. We also in 2014 took that to the next level with the production center. So, now we have live data streaming in at a high rate from all of our rigs, plus all of our well sides. We’re able to analyze that on the fly; call people out to wells that are down, understand what’s happening on the rig. And we’ve also lately been involved with the ERP implementation that again is allowing us to see all of our financials and all of our production data together. So, these have been transformational, and that’s the velocity part of the data puzzle for us.

And the last part is what I’m most excited about and that is the variety. When all the information is coming together, lots of data at a high speed and different types of data, we’re able to create these transformative results. So, we’ve got things like RPA that are automating processes. We’re working with groups like marketing. We’re doing remote frac monitoring. There is two types of remote frac monitoring. There are people that view the data, that’s on the BJ or Schlumberger screen, but there is also live streaming completion data that comes into our op center where we’re able to analyze it on the fly. So that’s the step change that we make is, our information is blowing into our systems where we can analyze it on the fly.

And then, we’ve combined the big data analytics engines and we evaluate things like frac fluids, proppants, perf cluster spacing et cetera. So, it’s been a transformative change, the last couple of years that would have been possible without the new technology and having set a foundation in the past.

So, the first thing that I want to talk about is marketing. That may seem like a small topic, but it really emphasizes it. When we think about big data, it is every aspect of Chesapeake’s operation. This is an area where in Mid-Content for example, we had a lot of tanks, there are wells that produced 0.5 barrel a day, 1 barrel a day. And so, when you’ve got thousands of wells, you leave thousands of barrels out on these locations unsold. So, one of our projects that we most recently completed was trying to optimize our oil haulers with the oil that’s left in tanks. And you see in an area like Mid-Con, it’s 88,000 of barrels of oil that’s just sitting one and three barrels a time in these different tanks. So, we’ve been working with our truck haulers to create automated routes where they do split loads and pick up all these tanks and kind of do a milk run to bring the value in. And it’s a small thing but for us, it’s $4.2 million of value in Chesapeake that’s just sitting in tanks that we’ve already produced. So, that’s a big thing we work for using big data to create value for us and our partners.

When we talk about technology in the Gulf Coast is I guess one of the best changes we’ve seen in the Company and it’s been followed quickly on the heels by the Eagle Ford. Again, this is something -- an area where we started long laterals a couple of years ago, transformed our fracs last year when we talked at Analyst Day about propagating, those wells are fantastic. And when you see it all coming together, you get things like this where we’ve got on one location a 133 million cubic feet a day of gas coming from one location, which is the implementation of technology and new completion designs. Other things that are coming down the pipe today, we’re drilling the first 15,000 foot Haynesville well. So, that’s something that hasn’t been done in the Haynesville yet. We also are completing or just finished completing our first 10,000 foot Bossier well, which has over 40 million pounds of sand in the Bossier. So, this really should open up those Bossier wells. We’re excited about that performance. So, not only do we have great things we’ve done in the past, we still have more to do and are continuing to optimize the Haynesville.

When you look at what that means, I love this production plot. It was one that we had at our Analyst Day a year ago, I had them fast forward it. When I talked about it at the Analyst Day, I highlighted that three rigs now do what 36 rigs did in the past, and you see it playing out as we roll forward. Over a two-year period, we’ve grown the Haynesville 30% with just three rigs. So, think about where the Haynesville -- there is rigs coming in, piling into the Haynesville these days, the rig count is up, but Chesapeake is able to grow production with just three rigs and that really speaks to it. It’s not just IP or a little bit of pop that we’re talking about, you see that wage there, and again 30% growth out of this asset with a very low rig count.

So, I’ll move on to the South Texas. Again, this is our oil growth engine for the Company, and longer laterals are continuing to drive the value there, but these enhanced completion techniques which are enabled and supported by big data are also adding a lot of value. We talked about a 15,000 foot lateral in Haynesville; well, we’ve already completed our first 16,000 foot well in the Eagle Ford, so again, something that none of the other peers are talking about as 3-mile long Eagle Ford wells. The results of it are fantastic. If you see on the plot here that blue line is the cumulative production from our 16,000 foot well versus some of our offsets and our peers’ offsets, the well had a peak rate so far 2,350 barrels of oil per day, not BOEs per day, barrels of oil. And if you were just to go up from 20 days, I mean this well is making three times what those offset wells are producing. So that’s a type of transformative change we’re seeing in our operations these days.

Now, I want to go into the big data, started off with the big data puzzle, but this is where technology and big data are really helping us come together to optimize development of the field. We have this Arena Roja Vesper project. You can see the wells on the bottom here. The 3-mile laterals we just described are on the red and they really look set to TD [ph] into these blue wells on the Northern part of the play. And what we’ve understood is our big data project is that targeting was very critical, whether wells were in or out of the plain, made a big difference on, not only the well that was being completed, but the offset wells as well. And so, what you see on the right hand side is those are the trajectory of the wells. So, we’ve purposely been able to drill and steer the well, so that they end higher in plane than the starting point of those blue wells. So, what that meant to is when the wells were being completed, we didn’t knock off all those blue wells, which is a big problem in our industry with these frac hits. So, trying to understand targeting trajectory and tying those two things together really is helping us mitigate the downtime and interference we see on these wells.

Now, it is also important to note the trajectory, because I’m going to highlight that that Chesapeake has really had a standard of drilling these wells down and up. So, basically, if you can imagine oil being produced at the top of those red wells and the oil flows down to the heel. So what is great about big data team, in the past when they were on their own, the big data could run regression and analysis, and looking back at the past and they’d go to the Eagle Ford team and they’d say, hey, we think if you drilled your wells in better porosity and permeability, you’ll make better wells and that operation guys were like, well, we kind of know that.

Well, what we’ve done this year is we embedded the big data team with the Eagle Ford team and now they can understand what’s important to the teams, but the geologists, like, they want to know what is trajectory, how does it impact the production of the wells, is it important or not, and the big data team can be, well, we can just load every well in the Eagle Ford and you can see exactly what targeting interval they are in, you can see the 3D image of the log and all that. So, that’s what they did with this project, in right. It’s still bit hard to see here, but there’s a map of every Eagle Ford well. What they did is pull from public databases the trajectory of every well in the Eagle Ford. And then, they said, well, let’s look at -- normalize these wells for lateral length and look at all the wells that were drilled up dip versus the wells that were drilled with the toe point down, and does that make an impact on performance. And what you see in the bar graph is that over a three-year period, it makes a difference of three barrels per well. Now, it may not seem like three barrels per foot. So, it may not seem like a big deal, but when you take three barrels per foot times a 5,000 foot well times $50 a barrel, that’s $750,000 of incremental value that you can achieve in Eagle Ford, just by drilling your wells up. Now, we had a good idea that this was the way to do it before going into this study. But, in two days, you could paint a picture here that, man, it’s really important if I can get another $750,000 out of our wells, and Chesapeake is one that does it really well. We’ve got 75% of our wells drilled toe-up. But if you look at some of our peers and it’s something that they don’t have these data analytics, they don’t appear to understand that that’s an important part of the development is, we want to drill our wells, pointed up, not with them pointed it down. So, those are things sort of big data can help us out.

We also realized that we don’t know it all necessarily, we’re trying to go from a know it all culture to a learn it all. So, the big data team, again, they came in and said, well, how can we help you? Completion guys, it will be great to know, what frac fluids are being pumped, how do they impact production and performance. The Big Data team comes in and they say, well, we’ll pull a frac focused database and you can see every completion design that’s pumped in the Eagle Ford and that’s what you see here is over time, the different completion styles that companies are pumping in the Eagle Ford. So, on the top, and these are colored from slickwater, which is basically water with a little polymer in it, linear gel and crosslinked fluid. So, you’ve got one company that doesn’t really change their design over time; you’ve got one that’s transitioning to water fracs only; you’ve got one that was doing all three, took break from it but then went back to where they are, but they’re maybe making some changes at the end.

So, these are the things that can help us and we think about drilling a pad of wells. We have six wells on a pad or $6 million well. It takes us $36 million to do a science experiment. Well, now, we can do these correlations like does frac fluid matter? I can learn from my peer, try to normalize for the rock properties, the trajectory of their well and see what impact do I think the frac fluid really has on performance. And so, these are things that we changed in our designs and we’ve got some wells coming on this quarter and next quarter, the best recent example of it, wells that have had a huge change in their performance because we are thinking of the little things right now, and it’s not always the big ones. Those things add up over time. So, when you think of trajectory and fluids, those improve your performance.

Other things that we’re looking at is back to this live streaming data. We go into the Eagle Ford teams, like, man, we want to understand how our wells -- when they have those frac hits, we want to shut those down, we don’t want to interfere with the other wells. What can we do? So, we go in, we already have automation on the wells, and we turn up the frequency that we pull a well. So, our well that’s -- the next pad over, what we want to do is monitor it while we are streaming in our frac job from the well that’s being completed and see if we can do something about it.

So, what you got here is an example of frac job that was pumped this week or last week and where we’re trying this new technology. And so, what you see on the top here is a production graph; it’s the pressure from the offset well and we’ve got it cycling now every 30 seconds. And the big data engine sees, oh, there’s been a pressure spike here, it sends a text out to the guys that are on the location and say, we’re seeing a pressure increased on this well, we want to do something about it. So, they decide that they’re going to pump a diverter on it. So, 10 minutes later, again, we pump the diverter on the well and you see that hitting bottom on the well that we’re treating. And what’s great about it is you see that pressure spike that we had on the well, has gone away. So, we’ve pumped diverter on the well we are completing now and it’s stopped the communication on the well because you can see as we get back to pumping here at a higher pressure, we’re not seeing that pressure continuing to increase in the offset well.

So, again, these are some ways that companies actually use big data. It’s hard sometimes, we will present in arm way, the big data analytics are important, they’re changing our world but these are some real world examples where integration of our data analytics and operations is transforming the results.

But the proof is in the pudding. Now, if you look at these graphs, these are the 60-day cumulative production for each well divided by 60. So, the average first 60 days of productions from both the Haynesville and the Eagle Ford, and they’re bend by the quarter that the wells have turned in line.

So, when we talk about operations, a lot of times companies are trying to improve by the next 5% or the 10%. When we think about what technology has done for us, longer laterals, integrating these big data solutions, you are seeing transformative change in our operations in both Haynesville and even the Eagle Ford, which doesn’t get as much press today. But, if you look at that far right graph, we’ve doubled the production from our Eagle Ford well over the last two years with integration of technology and longer laterals. We are testing some of these new designs that are again coming on in fourth quarter and expect that trend to grow. So, it’s something that I don’t think you see very often these kinds of results. We have highlighted some new completions in the Marcellus, in the Utica, or our lightest Marcellus well that’s 60 million cubic feet a day. We brought on lower -- Upper Marcellus formations, at 30 million a day, which if you scaled up, would be 45 million cubic feet a day well. So, we don’t have enough data for those wells to make this graph, but this is something you see in every Chesapeake-operated well that over the last two years, there is huge changes in the way that we operate in our capital efficiency.

So, it’s important to us as we’ve got this great new area called the Powder River Basin. We’ve got a hotspot advantage, we’re having better rock properties where we operate. It’s get a lot of stack opportunities. Again, we liked the Haynesville -- or this Powder River Basin, but now we love the Powder River Basin. We’ve got lots of, again, science over and we’ve got a lot of seismic. We’ve got multiple producing zones, we’ve seen rates as high as 2,200 Boe per day in the Sussex; 1,900 in the Niobrara; and almost 2,900 barrels in the Turner. So, we’ve got some formations that I’ve got a lot of potential with them. We have 100 penetrations in -- over 100 penetrations in the Turner. So, it’s defined where it is in our core. We’re just continuing to develop those. We’ve got a couple of new wells that have come on this week that are really exciting to talk about. And we’ve got Tim on stage and he’d be happy to share with those wells are doing.

But, it’s a huge asset for us and we think about the Powder. And what’s great about the way we’ve got this Company structured now is we can take technology from every aspect of our business and start to point it on the Powder River Basin. So, what we’ve learned about completion designs in again Eagle Ford, Utica, Haynesville, what works and doesn’t work for Utica. Utica has sandstone -- or not in Utica. Powder has got some sandstone, not shale. So, sandstone play is going to be different than a shale play. But, we can take what we know about hard drilling. Haynesville is a tough rock to drill. We make it look kind of easy, because we drill wells as fast as our peers, but it’s a hard formation to drill. But take those learnings and look drilling learnings from the Northeast and apply them on Powder and it really just opens up that we’re just getting started with these wells in Powders, we’ve got wells in again Eagle Ford that again there is 3 miles long and they take you 10 days to drill. If we can save 10 days of Powder well, again, think of one rig line can do in the Powder.

So, we’re really excited about just taking the full power of Chesapeake, applying it to Powder. That’s one of the great things about the structure is under me we’ve got drilling and completions and the big data teams. So, we can just share information quickly these big data solutions that come up with. We access FracFocus database for Eagle Ford, but we already have it for Powder. We know what all the peers are doing in powder. So, we can capitalize on that stuff once we’ve built the tool and share it with everybody.

So, just to reiterate, again, I’m really excited about Chesapeake. We know our balance sheet is a little bit stressed. But, don’t let that cover up the operational efficiencies. We’ve done our best work in the toughest times, these last two years. And you don’t see companies, hopefully, talking about wells that are twice as good as they were a couple of years ago. So, those are the things that we’re really excited about. Sometimes the challenges on the balance sheet mask the production performance, but our guys are doing fantastic work. We’re going to continue to focus on getting the debt down, coming cash for neutral, again ultimately improving our -- getting that cash flow neutrality and expanding our margins during the process.

So, again, thanks for your time today. Again, it’s great for me to be able to share. So, going to the weeds a little bit. We don’t always do that at these. But, there are some little things that just continue to add up and make a big difference over time for Chesapeake and we just don’t need to overlook, just things that the guys are doing on the frontline it’s just fantastic work and we’re excited to share it. So, thank you.

Question-and-Answer Session

Q - Unidentified Analyst

Thank you, Jason. And let’s circle around for questions here. Maybe to start off, so everybody is talking about big data.

Jason Pigott

Yes.

Unidentified Analyst

And so, from the Street’s perspective, how do you think we should look at the companies -- compare one company’s big data capabilities versus another? And then, internally, how do you benchmark your capabilities versus your competitors?

Jason Pigott

Ours are best. So, I don’t know. We’re really excited about it. I mean, that’s why I really wanted to provide that breakdown upfront because when you talk about big -- what is it? Because a lot of -- for some people, it’s just volume. I mean, big data means, I’ve got a lot of information; for some, it’s I’ve got streaming in, but the question is are you streaming in, again, Schlumberger’s data or is it your own data? And then, the variety, are you able to handle and process the variety. So, we call it at the 4Vs, the velocity, volume, variety equal value for us. And that’s what we -- it doesn’t mean -- good to make pretty streams and images and do correlations, if you can’t turn it into the bottom lines. So, again, those little examples I tried to show today are -- these are where the volume and the variety start to turn into value for Chesapeake.

So, we -- for that part of the business, we’re good. Everybody has got ultimately taken the big picture, their strength and their weaknesses, but I think we’re just -- we’re all trying to learn this together, we talk about the digital transformation at Chesapeake. This week, we had a two-day session where we were looking at the intelligent well. I mean, what does it mean for a well, if it were a robot? How would that robot operate? Could it tell you, what was going wrong with it? Does it -- can it start to predict it’s going to have problems, so, we can get out there and fix things before they break. So, the future -- we’ve done a lot, but there is a lot more for us to do. And I think different companies have their different strengths. And we’re attacking it a little bit differently, but the results are what matter to us, and we really see them.

Unidentified Analyst

Any questions from the floor? Right there.

Unidentified Analyst

Hi. I was wondering if you could offer some thoughts on the Haynesville, where you go from here. Is this something where you see like you’re running three rigs and one frac curve, is that something you’re looking at further growth or is that something just -- what your plans there?

Jason Pigott

I’ll let -- this is Tim Beard, he is actually in-charge of Powder River Basin and the Haynesville, so.

UnidentifiedCompany Representative

Yes. So, our plans currently are to continue to run three rigs and one frac through 2018. And part of the reason we’re doing that is just due to the nature of these new wells, right, we’re making 30 million to 40 million a day wells from these 10,000 foot laterals day in and day out. And I’ll tell you that the infrastructure wasn’t put in place for 30 million to 40 million a day wells, put in place for 10 million to 15 million a day wells. And so with those three rigs, we’re having to move around our acreage position and fill up the pipe here, fill up the pipe here, and fill up the pipe there. Can we solve that problem with a little bit of capital on the midstream side, absolutely we can. But, currently, we feel good about where we’re headed and we’re developing it in a way that we think is appropriate to add value to Chesapeake.

And those wells are currently sitting -- it’s greater than 35% rate of return at $3 a gas, the wells pay themselves out in a year to year and a half. I mean, they’re just phenomenal wells that we continue to drill. Jason’s pointed out our first 15,000 foot lateral, that’s going to open up other areas kind of on the periphery of our acreage that haven’t been quite as economic to-date, but you add that additional 5,000 foot to lateral at a very relatively small price, it’s going to drive the value across the field. And so, he also mentioned the Bossier well where we have our first 10,000 foot Bossier. We anticipate that well being very big, 30 [ph] million a day plus or minus is what we’re looking at, for that testing the inflow potential. He mentioned greater than 40 million pounds of proppant pumped on that particular well. We’re just going to see what the Bossier can do and then we’ll economically figure out what’s next for us in the Bossier as well.

Unidentified Analyst

[Question inaudible]

Unidentified Company Representative

It can absolutely grow production.

Unidentified Analyst

So, just continuing along the Haynesville, I mean, how big -- obviously, you achieved the 1 bcf per day milestone here, you’ve been there for quite some time?

Unidentified Company Representative

Right.

Unidentified Analyst

How do you think about the ultimate plateau for that asset? And your maintenance CapEx up in Appalachia is about $400 million to sort hold that kind of flat. What is the maintenance CapEx just for the Haynesville itself?

Unidentified Company Representative

It’s a great question. I’m not sure we thrown that number out there. But, I would tell you, in generality, it’s going to be somewhere around $250 million plus or minus, to keep our production. We’re sitting today at about 1.35 bcf, which is higher than we’ve been since March of 2014. Keep in mind we were running a lot more rigs back then than we are today. And so, with these big wells, we can run three rigs, one frac fluid and continue to grow that production.

Unidentified Analyst

Yes. There’s really monster fracs in the Haynesville now, 40 million pounds. Do you see any evidence that perhaps that may be growing up into the Bossier and perhaps straining both the Haynesville and Bossier formations?

Unidentified Company Representative

That’s a great question. I mentioned…

Unidentified Analyst

From micro-seismics and other.

Unidentified Company Representative

Yes. So, micro-seismic would tell you that we have potentially grown up into the Bossier. The question would be with that I would say gummier shale in between the Haynesville proper and Bossier proper, are we keeping that open after we frac through it, and is our proppant, we’re typically pumping slickwater, is our proppant falling back down, are we able to keep any of it in between to potentially keep that conduit open between the Bossier and Haynesville. I’ll give you a tidbit of information. We practiced Bossier well and we actually saw response, a slight one relatively to typical response we see from Haynesville, the Haynesville well, from that Bossier well, we actually saw slight pressure response and a production response on an offsetting about a 1,000 foot away from a horizontal perspective, Haynesville well. So, there is definitely some amount of communication, but how much is it and does that conduit between those two over time? That’s a question we’re still trying to answer.

Unidentified Analyst

Okay. Another question is four or five years ago, it was all the rage to manage production rates by choking back, thinking whether we reduce damage, stress to the frac, but maybe that’s no longer being practiced. So, is that -- could that be responsible for some of this comparable uptick in production that you showed...

Unidentified Company Representative

We’re actually drawing our wells down today much less than we did when we began in this play. So, we look at a pressure drawdown somewhere in the range of 25 to 35 PSI a day, which is very, very minimal. So, we take into account that pressure dependent permeability on every well, every day. And so, I would tell you that we’re drawing our wells down much more gradually than we ever have in the past. This is just a result of longer laterals, better completions. And then, honestly, the production team in the field doing great job of handling 30 million to 45 million a day on a daily basis.

Unidentified Analyst

Looking at the Powder River Basin, most of the wells you drilled here today relatively shorter laterals. Are there limitations on drilling longer laterals in your area?

Unidentified Company Representative

Actually there are several units and I would tell you no. So, we just drilled our longest Turner well, which was 10,700 feet. We’re still trying to figure out what we have in Turner, right. We’ve drilled six wells. We’ve completed five of those. All five of them have been phenomenal. Jason, mentioned we have two that we just turned in line. Those wells are about 1,500 BOE a day right now and we’re just now opening the choke right. The pressure is still actually climbing. We haven’t opened the chokes much. The Turner looks great. Not a limitation this minute on exactly how long we can drill, especially in those units.

UnidentifiedAnalyst

And your budget is going to come out early next year. Earlier this year, you had mentioned maintenance CapEx in 2018 about 1.5 billion. Is that still a reasonable number, is there a reason to think that’s sort of -- big data and everything, has that come down?

Jason Pigott

No. I think it’s still the number we’ve kind of gone that we would -- 1.5 billion is maintenance capital. We said our total capital spending would be less year-over-year, again some of the complexity of our settlements has gone away. So, spending will be down and production will be fairly flat to slightly increasing. So, I think the 1.5 billion is still a pretty good number.

Unidentified Analyst

And when you discuss potential divestitures, you divide your assets into basically three buckets. You have those that are truly non-core, you have sell down to plays we could still retain relatively good position, and then you have -- there is the possibility of basin exits. So, your $2 billion to $3 billion target of asset sales over the next several years, could you achieve your objective without exiting a major basin?

Jason Pigott

It would probably pretty different goal, especially to hit that $3 billion mark. I mean, we have done a great job. Again, I mentioned that we sold one just this week that was 20,000 acres for a $170 million or less. Again, A&D team is not going out of the park when you can do something like that. So, we’re still moving those. I mean there is a difference between some of the smaller things that are easily actionable, there’s money out there for those. The bigger ones are a little bit tougher to come by. But we did a great job in the Haynesville last year where we bought 80,000 acres for $56 million and sold 150,000 for $900 million. So, we are still working on cleaning up the perimeter of our fields. But, we may need to exit an area if we get to that $3 billion mark. Again, we are 100% focused on trying to improve the balance sheet. It’s going to take something big to get where we want to be.

The great thing is Nick’s team, the finance team has done a great job of pushing some of those debt maturities out. So, it’s not urgent that we get it done right away or moving asset out for a discount. So, we are still working that pretty aggressively. But, it’s top of mind to get to the $2 billion to $3 billion.

Unidentified Analyst

And with the recent rise in commodity prices, has the discussion -- A&D you market sort of change, has the bid spread between buyers and sellers, so that’s sort of begun to narrow?

Unidentified Company Representative

Yes, in a macro sense, maybe not, but this deal that we’ve signed this week, it was something that has been in the works for a long time but it got over the line pretty quick when oil prices spiked. And we have a couple of more that are discussions are getting much more material with those as well. So, I think it’s helping us. For us, we still need gas to improve in addition to oil, and I think that will help with some of the gassier areas with maybe creating opportunities there.

Unidentified Analyst

So, when we sort of think about the potential basin asset, we should be probably speaking more on the gas side because it’s something you want to maintain the oil?

Jason Pigott

We love the Eagle Ford, we love Powder. Powder is hard to get the potential, the full potential there because it’s still undeveloped and we’ve got so many formations left to test. So, there’s not a lot of oil assets left and we keep those two in your portfolio. But if we get the right price, again my house is for sell, if you’re paying me the right price for it.

Unidentified Analyst

And first thing is first, you need to execute on the $2 billion to $3 billion, but post the sale, are there additional steps that you’re thinking about it? I mean, at that point in time, do you think about -- or do you want to -- not now, later on, would you want have an acquisition sort of core key areas at that point after you get the balance sheet sort of in place?

Jason Pigott

Yes. I mean, we’re always -- we’ve got targets on both the acquisition and divestiture side of the business. And Doug mentioned on our last call that there is possible -- if we could use the balance sheet to make an acquisition or issue equity that was accretive to us, that’s something that’s not off the table either. Our goal is to reduce debt to EBITDA. So, you can work on the numerator or the denominator. We’ve had more focus lately on the denominator. But again, all options are on the table. Again, we’re a strong company. What we bring to the table when you think about acquisitions is the data, the information, the analytics, the technology. I mean, again, people there are active in the Haynesville. But it takes some 60 days to drill a 10,000 foot wells or they even give up on drilling 10,000 foot wells, so they struggle with 7,500 foot wells. So that’s what Chesapeake has the opportunity to bring to the table is all of those things that I told you about today can add value for both parties, if we can get.

Unidentified Analyst

And what is thought process about testing the Utica in 2018? I mean, you have a lot of other things in your place. I mean, is that just to understand the resource potential of that area? And then, would that be potential candidate for divestiture?

Jason Pigott

Yes. Some other operators have had great success, a little bit to the waste of us. Our plans are to drill a vertical well, take a core, get processed in our slab, understand the rock, and then maybe come up and drill a horizontal well there. So, it’s something we’ve got lot of the inventory in the Northeast, but there is another something out there that could help prove up the core, perimeter that add value that’s something that again we could also create value through new discoveries as well and let them to help improve the balance sheet.

Unidentified Analyst

And how are you thinking about service costs next year and how you’re thinking about headcount going forward in the possible ways of inflation?

Jason Pigott

Headcount, that’s interesting for us. At Chesapeake, when I started, excluding the services side, we were over 5,000 individuals, we’re closer to 3,000 now. So, we’ve had some attrition over the time that we’ve absorbed. The technology that we’re using today, when we talked -- I mentioned briefly robotic process, automation and those kind of things can make us a leaner figure fighting machine, where we can just absorb the attrition. So, wage inflation, not a huge concern for us. But, on the commodity side, there is a little bit of pressure, it’s just really depends on what oil price is going to do. It’s smaller, if it goes back to $50 and stays there, but if it’s $55, it could be 10%. What we trying to do is drill these longer laterals, which are more efficient that ultimately keep our economics high, even if we experience some of that inflation. But, it hasn’t been too tough slightly, it’s more on the completion and stimulation services side than the drilling side right now.

Unidentified Analyst

There was another question right there. And then, when you sort of look at this big data, I mean, how much do you think this could, if you sort of extrapolate over the next, let’s say three years, how much do you think you could actually improve range wise in terms of efficiencies or potential cost reductions?

Jason Pigott

It’s both sides, that’s what’s exciting. I don’t know, again, our completions have just transformed in a really short amount of time. Because we were able to finally view all the -- here is all the rock data. Here is the trajectory of all the wells. Our next thing is like, we’re looking at tortuosity. Not only if it’s just up dip or down dip, but how many little bumps and dents matter in a wellbore to prohibit, increase or decrease production. Again, we’ve got huge potential in Powder as we start to apply technology there. We’ve got great results so far, but what’s the next level of completion out there. So, the sky is the limit on the improving well productivity. We’ve got Utica test coming down the pipe, but it’s also the cost reduction. If we can get predictive with our equipment, understand when it’s going to go down, when a rod is going to part, those are -- I mean, our LOE is $500 million to $600 million. If it can stay at 10%, $50 million starts to run another rig for Chesapeake. So, there is a big price on both cost reduction side of the business as well as increasing productivity. And the good thing about Big Data is it helps you with both. So, hopefully that compounds for us in a positive way.

Unidentified Analyst

One last more question for me. You keep on highlighting all these great wells out of Appalachia. You are seeing additional pipeline capacity coming up in that region. Should we be thinking that Chesapeake is looking to grow up in that area, because all the wells you’ve been highlighting, maybe in particular in the Utica or…

Jason Pigott

We would love to. Utica, we’re not really constrained right now. It’s Marcellus where we’re constrained. And we don’t have a lot of new capacity on the new pipes coming down. I think in the future, there is another $200 million that will pick up. But where we can find that niche hopefully is just some of these other operators that can’t necessarily fill all the capacity. On a spot basis, we’re able to get gas out, but it’s something that I guess a big priority for us, because we’ve got a lot of value traps behind pipe and in the ground. So, just slice the debt reduction, getting gas out of Marcellus is right there with it.

Unidentified Company Representative

All right. I think that’s it. Thank you very much.

Jason Pigott

Thank you.