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EP Energy (EPE)
Q2 2018 Earnings Conference Call
Aug. 10, 2018 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, and welcome to the EP Energy second-quarter 2018 results conference call. [Operator instructions] Please note, today's event is being recorded. I would now like to turn the conference over to Jordan Strauss, manager of investor relations. Please go ahead, sir.
Jordan Strauss -- Manager of Investor Relations
Thank you, Rocco, and good morning, everyone. Thank you for joining us today at EP Energy's second-quarter 2018 financial and operational results conference call. I hope you've had a chance to review the earnings release and supplemental presentation that we published yesterday. Earnings release and presentation are available in the Investor section of our website, epenergy.com.
I'd like to remind everyone that on today's call, we'll discuss forward-looking statements and certain non-GAAP financial measures. We encourage you to read our full disclosures on forward-looking statements and GAAP reconciliations, which can be found at the end of the company's earnings release and our documents on file with the SEC. These documents are also available on our website. Joining me on the call this morning are EP Energy's president and chief executive officer, Russell Parker, and senior vice president and chief financial officer, Kyle McCuen.
And with that, I'll turn the call over to Russell.
Russell Parker -- Chief Executive Officer
Thank you, Jordan. Good morning, everyone, and welcome to our second-quarter call. We continue to have near-term successes in the company and are really pleased and excited with the progress that we've made over the last nine months. And we're certainly excited about our potential for long-term value growth.
As you see from the materials that we published last night, our oil rate is growing, our EBITDA is growing, LOE is continuing to work lower and our G&A is becoming more efficient. So things are certainly moving in the right direction. We also included a little bit in the materials a little summary on our Q1 completion activity in the Eagle Ford. This shows a real nice improvement, we think, for our long-term value potential.
The reason we included that and the way we did it is to compare all of our Q1 activity in the Eagle Ford to all of its prior -- all the prior offsets. Every single well that we completed in the quarter, as a matter of fact, is included in that analysis. And what you see from the results is that our capital dollars are actually becoming more efficient. So when we compare all of the wells completed in that quarter to all of their immediate offsets and compare them not only just on a rate basis and a cum basis and EOR basis, but really a dollars spent to generate economic barrel, we're showing about a 20% improvement compared to our prior results and prior offsets, which is quite exciting.
And we'll be excited -- and we'll be happy to talk more about that during the question-and-answer session. Something also I want -- next, I wanted to address this morning is, as many of you have seen in the notes and certainly from many of the questions that we've been receiving overnight, you'll notice that we are taking advantage of our high margins in the Eagle Ford in this current time period to accelerate our Eagle Ford activity in the second half of the year. As a matter of fact, we'll be completing about twice as many wells in the Eagle Ford in the second half of the year as we originally anticipated. And of course, that's because we're receiving quite a nice margin in the Eagle Ford due to the current pricing structure.
In addition, we're seeing quite significant improvement, as demonstrated by the material, in our well results and with all of the changes in the designs that we've been making relative to our completion style. So with that, there is a good enough short-term impact as well. When you accelerate activity, you're going to have to shut in your immediately offset wells. So we're going to see a little bit of an impact for that in the second half of the year.
However, we think -- we know all of this activity is actually going to benefit us in 2019 and set us up for probably on the order of about $10 million of incremental EBITDA from the incremental activity as we accelerate that activity into the second half of the year. We are also adding a third EOR pilot. We had originally planned for two for this year. We are encouraged by what we're seeing thus far.
So we've decided to add a third pilot, so three will be operational by the end of this year. And in addition, we've decided to add two more horizontal pilot wells in our Altamont program. So we originally planned for two, we now will have four. Those are currently underway and will be completed during the third quarter.
So by the end of the year, we'll have a decent amount of results -- early term results on those horizontal wells in the Altamont, as well as our EOR pilot. Everything we're doing right now in the company is focused on creating long-term value and long-term value growth. So with that said, we're being very programmatic in our endeavors. We've tried a lot of things.
We're now letting all of these experiments take some -- we're giving them some time to show their value impact and show the results. And ensure we'll say, "Look, we see quite a bit of improvement just in the near-term metrics." As I mentioned, our oil rate is growing. It was on a decline. EBITDA is now growing.
That's a function of not only oil rate, but oil prices. Our LOE continues to work lower, which helps on our cash margins and our G&A is becoming more efficient. So all of these things combined with what we're doing operationally out in the field, we think really has the potential to unlock quite a bit of value over the long term for the company. That's why we're excited to be here.
That's why we're engaging in the endeavors that we are. That's why we're trying the experiments that we're accelerating, and that's where we see the future growth and the future potential of the company. So with that early introduction, I'll turn it over to Kyle for a summary of our Q2 financial results.
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Thanks, Russell, and good morning, everyone. Q2 was a strong quarter for the company as well. We made progress on several fronts. We generated adjusted EBITDAX of $215 million, which is a significant increase from the last three quarters, and our cash costs continue to trend lower, specifically on LOE and G&A.
One thing to note on G&A, we recorded a one-time $2.5 million charge to settle a landowner dispute related to an acquisition of properties we made in 2016. Absent that charge, our G&A would have been approximately $0.30 per barrel lower. Our debt maturity profile significantly improved. In May, we successfully extended our reserve-based loan facility to November 2021.
And the refinancing significantly cleared our runway allowing us valuable time to execute on our new projects and evaluate A&D options to improve our financial position. Liquidity grew over first quarter. We ended the quarter with over $700 million of available liquidity, which includes a completely undrawn RBL and approximately $100 million of cash on our balance sheet. I think this sets us up well for the second half of the year, where we expect EBITDAX, at current prices, to cover capital and interest, excluding working capital and timing of cash capital.
Now, this is a significant improvement over the second half of last year, where we were negative by over $100 million on the same measure. Also, we've taken steps to enhance our 2019 oil price protection. Since our last call, we layered in another approximately three million barrels of three-way collars with a forward price of approximately $60 and a ceiling of $70 WTI. These hedges now protect over 50% of our '19 oil production, using our -- using the midpoint of our 2018 oil production estimate, while retaining attractive upside exposure.
You will also note in our slide deck, we layered in another -- we layered in one million barrels of 2019 mid-cush swaps at WTI minus $6.50, and we'll continue to monitor markets to layer in -- potentially layer in more protection -- price protection on this front. I would note, for 2018, our Permian realized oil price is close to 100% of WTI, given our mid-cush hedges. As a final note, you may have seen from the recent Form 4 filings, Seabed Veil Investment has reported selling a portion of its shares previously registered back in 2017. Seabed Veil is one of the co-investors that reports holdings under Apollo for SEC purposes.
However, Seabed makes investment decisions independent of Apollo and does not have board appointment rights or otherwise receive nonpublic information about the company. I would note these sales have increased our public float, and our sponsors, that include Apollo, Riverstone, Access and KNOC, all continue to hold their shares. With that, that finishes our prepared comments. And we are now ready to take questions.
So I'll turn it over to you, operator.
Questions and Answers:
Operator
[Operator instructions] And today's first question comes from Scott Hanold of RBC Capital Markets. Please, go ahead.
Scott Hanold -- RBC Capital Markets -- Analyst
Thanks, good morning.
Russell Parker -- Chief Executive Officer
Good morning.
Scott Hanold -- RBC Capital Markets -- Analyst
Russell, could you talk about the, I guess, new strategy in the Eagle Ford? It looks like you're drilling some pretty long laterals. You're expanding the EOR process out there. Can you sort of -- you kind have highlighted that there is some short-term issues with, obviously, production being lower, but probably some long-term gains. Can you give us a sense of what this could do to enhance 2019 and beyond?
Russell Parker -- Chief Executive Officer
Absolutely. So -- and you're right. When you -- two things I should reiterate here. One, we're adding EOR pilots.
And because of the way that we're actually engaging in this process, we're actually finding that our pilots are impacting more wells, which is a good thing for the long-term because we think with the same amount of capital, we'll be able to cause that uplift on a larger piece of acreage, which is good. The short-term impact, however, is that that means you have to shut-in more wells to help build up that reservoir pressure. So it does have a near-term impact on rate, but we think it's going to have a very positive, we know we'll have a very positive, long-term impact on value creation, because these pilots should be able to impact a larger portion of the reservoir than what we had originally anticipated. And then on the same front, in terms of drilling longer wells and in terms of well spacing, completion designs and really just making our capital more efficient, we have -- so thus far we have experimented with a wide range of pound per cluster completion style.
We are watching all of these wells to see how they improve. We tailor that pound per cluster pad by pad. So really we're trying to design our capital to most optimally develop not just well by well or even pad by pad, but an entire lease. And so what that means is that we don't just look at a constant well spacing across the field or a constant completion design across the field.
And what that does for you is that ends up making your capital more efficient. As a matter of fact, I'll point to a couple of the slides that were in the materials from last night. In there, you see two groups of wells. One group is our increased completion design.
So in that group of wells, we actually had more pounds per foot and more pounds per cluster than the offset wells. So the new wells are actually performing better than the offset wells, as you can see. But the more important note is that economically the new wells are performing better. So if you look at EUR per dollar spent or F&D rather and rate of return, we see an improvement.
And we showed that graphically. We actually took the cum economic BOE divided by the dollar spent for well and that way you can get a quick gauge as to whether or not your dollars are actually becoming more efficient. And then on the next slide we actually showed a group of wells that were also completed in the quarter, in which we actually dropped the pounds per foot, but increased the pounds per cluster. So these were actually cheaper wells.
They were less expensive wells, and they are performing pretty much in line with their immediate offsets. And the key is knowing how those wells were completed and how much money was spent. Because really what matters is not BOE, not necessarily rate, not necessarily cum in a certain time period, what really matters is how much money did you spend to generate that economic barrel, right? That's what really matters. And so that's what we're really comparing and this how we judge all of our projects as well.
So here on this group of wells, as you can see the well performance is similar, but the well performance related to the dollars spent is about 20% better -- actually, a little bit more than 20% better on this group of wells. So what does that means? I'll speak to this part of the equation just in completion design. What that means is that our capital is becoming more efficient. And what this -- the impact this will have is to continue to work down the amount of maintenance capital that we need in order to hold rate flat.
So we think we've done a good job in the first part of this year, building our rate back up to say that 46,000 to 47,000 barrel a day range, which is where the company was at the beginning of '17. Now the goal is to try to make our capital as efficient as possible to see how we can maintain our rate in this range, while spending fewer and fewer dollars. And so primary focus is certainly completion design, and next focus is going to be on longer laterals. I'll touch on that for a second, and, of course, for the real long-term is EOR.
Really, we think that is probably our best opportunity to have very efficient capital for the long term, but it is -- we are in the early stages, very early stages of that project. You'd also asked, Scott, about longer laterals. So there is a large portion of our field that would make -- that makes quite a bit of operational sense to develop with one corridor of 15,000-foot wells instead of two corridors of 7,500-foot well, and there is an obvious cost savings that comes from that. So your F&D should reduce.
Now before you develop plans like that, we think it's very prudent to; one, make sure we understand and have optimized our completion designs for that particular rocks or actually, do we actually put a core in that area earlier this year and we're analyzing it now to make sure we can tailor in our completion design. In addition, you want to make sure that your wells function operationally as they should. I know some folks have seen some degradation in terms of EUR per foot as wells become longer. If the entire lateral is not landed directly or is not all communicating back into the wellbore, then you can't experience those issues.
And so that's why we felt it's important to go ahead and start trying a couple of different techniques on our longer laterals, get a couple of them down, which drilled record drills this quarter for us in the Eagle Ford, and we want to make sure that these wells are going to perform up to our standards before we jump into that development. But for the long-term, this could have a very significant impact on the company because as I said, we have got -- in terms of the amount of acres that we've got to develop with potential 15,000-foot laterals, it could be quite expensive. So all three of these projects, again, are all working in the same direction. The whole idea here is to make sure our capital is as efficient as possible.
And what that's going to do is continue to drop our maintenance capital down. Prior periods, I think it's been closer to maybe $600 million. Right now, we're working it down. I'd say true maintenance capital for just drilling and completion and production equipment only is going to be in that probably $475 million to $500 million range.
And with all of these projects that we're working on, especially with the EOR, the goal, of course, is to continue to work that number down, down, down, such that we're able to maintain our EBITDA and actually throw off more free cash flow after capex. So long-winded answer, but hopefully that tells you what you needed there, Scott.
Scott Hanold -- RBC Capital Markets -- Analyst
Yes. And I guess, there's just one component that just a little bit more color. The EOR project seemed like this is something that's going to take a little bit of time. Some of this development patterns in the longer laterals may be something we could start seeing the benefit in '19.
But again from our seats, you'd certainly on the 2018 numbers, production is a little bit softer, capex is a little bit higher, but in theory, what will this do to '19? Should we expect better efficiency in '19 based on what you were doing here in the back half of '18, if you can quantify that? I'm trying to avoid -- of course, you did try to give us 2019 guidance, but can you just give us a little bit of color there?
Russell Parker -- Chief Executive Officer
Yes, certainly. We're not ready to do for -- to guide for 2019, but all of these decisions are done -- are made in the guide of exactly what you said there, Scott. And certainly, from a timing standpoint, look the EOR is going to have a very smaller impact on '19, that's really a much longer-term project to have an impact at scale. The completion designs and the longer laterals will have a much larger impact on '19.
And so probably the best way I could say -- the best way to phrase it, rather than trying to give guidance, is the goal of all this and the target of all this, and it's a little bit of incremental capex, right, probably about $200 million to $225 million, but we feel by developing the field this way, infilling as quickly as we can to our offset, so basically mowing the lawn, making sure that we're optimizing our completion designs, we should end up shaving off ideally our goal is $50-plus million of maintenance capital. So that's probably the best way I could guide you. Now in terms of what happens in '19, of course, we'll have to look at prevailing prices and see what happens with our inventory, what acquisitions and divestitures that you make in order to actually set a '19 budget. But if we were to keep -- if you were to take the exact properties that we have today and without thinking about do I accelerate or do I decelerate, the goal of all of this work and the changes that we're making, we feel is going to help us drive that maintenance capital number down per year on that order, $50-plus million.
Scott Hanold -- RBC Capital Markets -- Analyst
Now that's definitely helpful. And as a follow-up question, you all have initiated the third EOR project, you're drilling a second. There are two more horizontal wells in the Altamont. It seems like, I would have expected that to be delayed a little bit until you got some results or is there something you saw in the horizontal Altamont before completing it and with some of the initial data in the EOR project that gave you confidence that this is the right thing to do and we need to go forward with this?
Russell Parker -- Chief Executive Officer
Absolutely. So I'll speak about the horizontal wells in the Altamont. As we've dug through the geology, looked at all the activity in the based and look at our rock compared that to what has been going on, we found that we really wanted to test two benches, and we wanted to test them with two different completion designs to already try to understand what's within the art of the possible of finding a development cost of rate of return there because we've seen what other operators have done. In terms of completion styles, we have some other ideas that we like to try, but, of course, we need to normalize that result.
So that's why we added two more wells into that project for this year. On the EOR, yes, we are encouraged by what we see. We think we're able to impact a large portion of our reservoir, a more larger portion of our reservoir than we originally anticipated with our first pilot. And so we're encouraged by that.
We're going to add the third pilot, and this is a small portion of our capital budget, but it's a meaningful portion, we think. And you're right. And in terms of calling it on the uplift and on the actual economics, we're very much in the early innings. We're in the top of the first innings, so we don't know the score yet.
But we certainly are encouraged by what we see, and so we felt encouraged by that and want to expand the project. Basically now what we're going to do is try to cover our entire acreage position to understand the impact as you change your fluid types and as the pressure in the reservoir changes, and that will have really not much of an impact on '19, but that's the impact for 2020 and the years beyond. But the sooner we can get that process started and the sooner we can learn about that, the larger impact we can have -- or the quicker we -- more quickly we can accelerate that impact for the company.
Scott Hanold -- RBC Capital Markets -- Analyst
All right. I appreciate that. Thank you.
Russell Parker -- Chief Executive Officer
Thank you, Scott.
Operator
And our next question today comes from Joe Allman of Baird. Please, go ahead.
Joe Allman -- Baird -- Analyst
Thank you. Good morning, everybody. Just a few questions here. So first, Kyle, in terms of the financial plan, I know there are a lot of moving pieces here, but I think the next debt maturity that's upsized is the May 2020s.
So what are your thoughts on how you handle that?
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Yes, Joe. We've got multiple options, I think, available to us to address that maturity. The options include using proceeds from a potential asset sale, potentially financing or, if needed, we can use cash, cash on hand liquidity. I think the key thing for us is we've got time.
Yes, it's two years away, probably we'll, obviously, deal with that sometime before its maturity. But that really gives us time to implement these new projects and improve the financial position of the company such that it could lower the cost of using a few of those options.
Joe Allman -- Baird -- Analyst
Very helpful. And Russell, in terms of the portfolio composition, I know, you've done a lot of testing so far, still just pretty much middle of the year. Any conclusions about where you think the portfolio composition will reside over time?
Russell Parker -- Chief Executive Officer
Well, you're right. It is still early. I think we are -- I know, we're very encouraged by what we've seen early on in the Eagle Ford and so we're accelerating our activity into that. We've tried some new things in the Permian as well.
But as you can see from the materials here, we're pretty conservative and before we like to call it and say, here's what we think we're doing economically from F&D rate of return standpoint in terms of how -- just how successful the wells are. So we need a little bit more time with that. It will be the end of the year before we know more about the horizontal potential, at least, to assume even one portion of our field in the Altamont. So what we're focused on right now is where we can physically grow the barrels, and we have very solid results that make sense for today.
That doesn't mean that we won't change that capital allocation going forward. But based on early results, that's what makes sense. And so that is why we're accelerating activity for now at least into the Eagle Ford. Now in terms of something you may have been -- or were you referring more to the A&D market?
Joe Allman -- Baird -- Analyst
That's helpful. Now in terms of -- yes. So I mean, just -- right now you got three assets and you got a lot of debt, so you got to kind of figure what to do. And so I'm thinking about both actually?
Russell Parker -- Chief Executive Officer
OK, all right. Well, fair. So we are very active in that space. We're looking for certainly things that are accretive to bolt-on.
You know in terms of divestiture process, we have made one small divestiture in the last nine months. We don't have anything actively marketed right now. Certainly, we do have a lot of debt. So -- and I have mentioned this before.
Surprisingly, even though I say it publicly people don't just in my office with large checkbooks, but if somebody is very interested in something we have, of course, we're going to entertain that idea if it's accretive to us. And we are exploring a number of different kinds of structural options as well to help improve our debt metrics with time. Certainly, making the capital more efficient, dropping the LOE, that all helps, but we're all very aware even though we are on the path to decrease our debt-to-EBITDA, we're laser-focused that we need to do that really at an even faster pace. And so that's a major focus of the company.
We are very active in that space, have nothing to transact to really speak about as of yet. But certainly absolutely, to your point, we have a lot of inventory. We have a lot of great rock. I can't anticipate that with our capital structure, this will be our footprint forever.
It's probably the best way I can say that.
Joe Allman -- Baird -- Analyst
That's helpful. And then in terms of Permian, after you finished the 3Q completions, I think you're basically shutting down that program. My assumption would be that in the first part of 2019, there would be little or no activity in the Permian as well, especially because you've got -- your basis hedges are not quite as good in 2019 as they are in 2018. Is that a fair assumption that in the first part of 2019 probably very little or no activity in the Permian?
Russell Parker -- Chief Executive Officer
I don't know. I wouldn't say no activity, and we're actually working on -- we've got our base production hedge as the incremental. If we were to grow the production quickly, just like anybody else in the Permian, it will be dealing with spot basis, which could be painful. We are working on improving that position for the long term, and we think there is, obviously, some structural things that are happening in the basin and the reservoir that will help to improve that as well.
So and then also I want to see how our new completions in the Permian perform. So I'm not really -- I'm not sure to call it yet, Joe, that I would say that there would be no activity. There may be less activity than the Eagle Ford, but we'll just have to -- part of that's just scope and scale. But we'll -- as we're closer to Q1, we'll certainly have more certainty on that.
Joe Allman -- Baird -- Analyst
That's helpful. I guess, on the Permian testing, it sounds as if you don't really have any conclusions about any of the new concepts you tested in the Permian so far this year?
Russell Parker -- Chief Executive Officer
No conclusions yet. The wells are just now -- some of them -- just now they're coming online. And like we demonstrated here, you'll never see us quote a 24-hour IP. We really don't even like to hang our hats on IP 30s.
We really like to give wells, at least, at least 90 days or more, if we can, performance before we start to talk about results.
Joe Allman -- Baird -- Analyst
And then lastly, on the Eagle Ford, those Slides 10 and 11, my conclusion is that just I look at the slides, the increase completion design is better than the decrease completion design, even on a dollar -- BOE per dollar spent basis. And are you trying to say that even if you decrease the completion design and those wells are cheaper, so if you had to just drill cheaper wells, you're still getting an uplift in terms of BOE per dollar spent. Is that kind of one of the messages you're giving here?
Russell Parker -- Chief Executive Officer
Well, it's really that we don't take one-size-fits-all. We think that you have to engineer each pattern and look at each situation. And in some instances, depending upon where the wells are land at that particular zone and how their space, a smaller or larger completion design may be more capitally efficient. And so that's really what it comes down to is.
Ultimately, you want to spend a little -- a few dollars as you can to maximize the recovery on our entire lease right. So in some cases, depending upon -- and part of it depends upon how the prior wells have been drilled, right, and how they are spaced and you've to work with that. So the key there is just looking at, OK, what is the situation and how do I optimize my remaining dollars to get the best economic recovery for the dollars spent. But part of what we wanted to point out on the wells with the smaller completion design is if someone would say to just go to public data and pulled the well results, you might look at that and say, OK, well they managed to match to offset well results.
And that's true when you look at just rate. What you really have to consider is how much did you spend to match the offset well results, right. And we really think, at the end of the day, right, that's what matters, how many dollars did you spend to get how many dollars back. That's the most important thing.
Joe Allman -- Baird -- Analyst
Got it. OK, very helpful. Thank you.
Russell Parker -- Chief Executive Officer
Thanks, Joe.
Operator
And our next question today comes from Derrick Whitfield of Stifel. Please, go ahead.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Thanks. Good morning, all.
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Good morning.
Russell Parker -- Chief Executive Officer
Good morning, Derrick.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
With regard to your second half guidance, could you help us better shape Q3 and Q4 production estimates? Specifically, with well guidance, that 5% down in Q3 and 5% up in Q4 seemed reasonable based on the timing of your activities?
Russell Parker -- Chief Executive Officer
Definitely, Q4 is going to be toward the higher side of the guidance, and probably Q3 is going to be toward the lower side. So we're going to a little bit flat and then building into a ramp toward the end of the year.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Got it. Very helpful. And then, Russ, going back to your comments on Eagle Ford, what are your pre-drill expectations for the 15,000-foot laterals? Are you specifically, expecting with two times the lateral, you get 1.75 times the EUR at 1.5 times the cost?
Russell Parker -- Chief Executive Officer
So right now, we have not -- on our inventory wells, we really haven't seen much degradation at all in terms of EUR per foot over the lateral as the lateral growth gets longer -- or becomes longer. Now in some basins you will see that, and certainly if you have operational problems, you'll see that. Our goal is to make sure that that doesn't happen, and again that really involves how the will is landed, how it's completed and making sure that the entire thing -- the entire lateral is communicating to you. So we haven't seen that kind of impact.
But in terms of the cost savings, the way I would phrase it to you is, say, if you move to 15,000-foot wells from 7,500-foot wells, we believe we're going to touch the same amount of rock, we're going to, ultimately, recover the same amount of reserves, but you're going to shave, at least, honestly, about 12% to 15% out of the total cost structure because of the corridor development, the production equipment that you have to put in there, just the extra surface casing so on and so forth, at least on that order of magnitude to develop the same amount of reserves. So if we peek back to even this path show here, what that's doing is just allowing us to develop more economic BOEs for the -- per the dollar spent. It just makes our capital that much more efficient, which helps us get our capital -- our maintenance capital down and, ultimately, grows long-term value for the company. So but right now, the key is making sure that operationally everything goes smoothly.
That's the key, right. And so that's why we're doing a couple of wells this year to make sure that our thesis on how to do that accurately works and works well, and we're going to justify those results against our immediate offsets and then build the plans out for the long term.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Makes sense. And then lastly for me, staying on the Eagle Ford, the read-through in your decision to add an incremental EOR pilot is clearly positive. Can you comment, if appropriate, on what percentage of your position you could de-risk following the three pilots?
Russell Parker -- Chief Executive Officer
The plan is actually to de-risk pretty much all of it. So we're going to cover basically from our oily standard role to our gassy standard role and to determine the impact as you change fluid type and pressure.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Very helpful. Thanks for taking my question.
Russell Parker -- Chief Executive Officer
You bet.
Operator
And our next question today comes from Sean Sneeden of Guggenheim. Please, go ahead.
Sean Sneeden -- Guggenheim Securities
Hi, thank you for taking the questions. Maybe just first, could you just, Russell, bridge us on the prior production guidance because I know you kind of outlined the $500 million on the sliding scale? Is the balance all just shut in kind of temporarily? Or how should we think about that?
Russell Parker -- Chief Executive Officer
That's exactly right. So again we're taking advantage of the margins in the basin. We've got a drillco in the Eagle Ford as well, so we're taking advantage of the juiced economics that come to the operator with that. And now what that means though is that when you double your completion activity, you've to make a choice.
You have to decide, well do I go compete, well it out in space and set up a problem for the long-term? Or do I use that incremental capital to try and fill in all of my active leases as much as possible, right, which means I'm going to offset our recently completed wells, which means you have a shut-in period for those offset wells. So we found there's two methods to really -- three methods, I'll say, to really making sure that you develop all the rock appropriately and mitigate frac interference. So first and foremost is to complete the infill wells as close in time as you can to the parent. That's the most important thing.
Next, we have our process to both shut in and then pump in and hold pressure on the offset wells, while we're completing the new wells. So -- and we found that with that, we are able to mitigate pretty much any damage. As a matter of fact, our infill wells in the first quarter were outperforming their offset parent wells, so we were pretty pleased to see that. But what it does mean, in order to really mitigate that damage and do the best thing for your dollars spent over the long term and the best thing to make sure that you are recovering the most amount of hydrocarbons you can per well.
You really want to do that as near term as possible, which means you have to take a short-term impact by shutting in that offset well. Certainly, if we just drill wells out in space, we could have a lot more near-term production and possibly, if they were short, spend less capital. However, we will be setting ourselves up for a rough 2019 because the longer you wait between your parent well and your child well or your infill well, the more likely it is that your infill well will not develop new reserves because you've created a pressure sink at that parent well and you end up retreating the same rock. So that's why it's important to do that.
So you're right. The change in the production guidance -- you've to kind of lock yourself through the entire decision-making process. It's, OK, we want to let our new wells in the Permian certainly have some time to take some impact. The margins are great on the incremental barrel in the Eagle Ford.
We have a drillco that we can utilize there, let's accelerate activity. Then you have two choices as to how you accelerate activity. Drill wells in space or infill your recent offset. And we feel like the best thing to do for the long term is to infill the recent offset.
However, that does mean we're going to have a near-term impact on production, and so that's really the crossover there. We do have a little bit of an impact from a sliding scale royalty and then, of course, there's also a little bit of a near-term impact from EOR because in order to engage in that project, we're shutting in the wells and valves such that they will -- such that the reservoir can build pressure around the wellbore.
Sean Sneeden -- Guggenheim Securities
Got it. That makes sense. And just put some numbers around it, like a quick math would kind of suggest around maybe 2,000 a day or something at midpoint. Is that kind of how we should think about shut-ins? And should we think about those volumes also kind of returning in '19 and beyond once the completions finish up?
Russell Parker -- Chief Executive Officer
I think your math skills are just fine.
Sean Sneeden -- Guggenheim Securities
Perfect. I appreciate that, and then just two quick ones for Kyle. I appreciate your -- the commentary on free cash flow neutrality in the second half. Is that the goal or target really kind of going forward that you're trying to manage like, at least, you have an EBITDA to kind of interest part in plus capex.
Is that how you guys are kind of thinking about?
Kyle McCuen -- Senior Vice President and Chief Financial Officer
I mean, certainly, that's been a state of goal that we've shared on past calls. Cash flow -- getting the cash flow neutrality; we're getting the benefit of our capital program being front half-weighted in 2018. So that's given us -- our profile to be more cash -- ability to, probably, EBITDAX to cover our interest and our capital. And I think going forward, I would say, our goal would be to kind of have the same free cash flow neutral profile.
Now I think the debate will come where we spend capital above our maintenance capital level, we'll have to weigh the merits, does it unlock value? For example, doing more EOR pilots or horizontals. And then how does that compete versus paying down debt or adding liquidity. So we'll continue to look at capital through that lens. And I think that's kind of what you see in 2018 as well.
I think we've been very judicious about our capital for this year. And yes, we're increasing capital versus our previous guidance, that's all for the purpose of unlocking value.
Russell Parker -- Chief Executive Officer
And let me tag on to what my colleague said too. Again, the technical work that we're doing this year is all under the guidance of actually helping to reduce that maintenance capital such that -- you're right, we can make that -- going forward, you can maintain rate, cover all of your expenses, potentially even through an awesome cash flow that will allow you to do some more things, and then it's just a question of if we want to accelerate what's the impact to the company of accelerating capital beyond that point.
Sean Sneeden -- Guggenheim Securities
That makes sense. And then Kyle, it looks like you guys repurchased some of the unsecured. I guess, specifically, some of the '22s and '23s. What was the driver there? And can you just remind us on your ability to do more open-market repurchases?
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Sure, yes. So early in the second quarter we did conduct some open-market debt repurchases. I think they were, in my view, done in attractive prices. We repurchased about $20 million of debt for roughly $10 million of cash, so about $0.50 per dollar.
And so since that time, our prices on our debt have traded significantly higher, making that a less attractive option versus investing in the drill bit. But we'll continue to look at that as an option going forward, should those prices become attractive again. Now in terms of our flexibility to conduct open-market repurchases, we certainly have -- we've got baskets in our various debt agreements that allow us to conduct those repurchases, and it just varies, Sean, by a tranche. So I'd -- rather than get into the minutia of the basket per each tranche, I'd say it's well north of what we did in the second quarter.
Sean Sneeden -- Guggenheim Securities
OK, that's fair enough. And just one last one for me, can you just remind us, are the Altamont horizontals included within guidance at all? Or has that really not been factored in?
Russell Parker -- Chief Executive Officer
They are, but they don't have a rate impact, except for just a tail of the year. So for the entire year and even to the second half, it doesn't have a very large impact. And we have a pretty conservative forecast on those right now, honestly, because we're -- we've seen what other operators have done. But for some of those operators, they've had marketing issues, and so they haven't been able to produce their wells full stream.
Certainly, there are current marketing constraints for some folks day-to-day in the basin. So we have a pretty conservative forecast, and they end up making a pretty small impact to even to our current Q4.
Sean Sneeden -- Guggenheim Securities
Got it. That's very helpful. Thank you very much.
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Thanks, Sean.
Operator
And our next question today comes from Gail Nicholson of Taylor Group. Please, go ahead.
Gail Nicholson -- KLR Group -- Analyst
Good morning. Just quickly in regards to the sliding royalty agreement with the University Lands, has there been any discussion with them in regards to the widening of the basis, maybe oscillating that agreement maybe in '19 not to be linked to WTI, but be linked to WTI less basis? I was just curious if you guys had those discussions.
Russell Parker -- Chief Executive Officer
So hard to comment because we're actually in the middle of discussions around a number of things. So -- but yes, the concepts you mentioned is -- does not fall on deaf ears, maybe I'll say it that way. But we're actively working that.
Gail Nicholson -- KLR Group -- Analyst
OK, perfect. And then turning to the Altamont, what are the costs for the horizontals? And then are those -- do those horizontal wells that you've there being added, are those falling under your JV agreement with Tesoro? Are those 100% EPE wells?
Russell Parker -- Chief Executive Officer
So they are JV wells. And in terms of the cost per well, right now, we think they're all going to come in probably just a little bit north of $10 million. We think there's a lot of things, though, that we can do long-term to actually drop that cost structure down. But as it happens in any program like this when you start it out, usually you're kind of in a high-cost period while you're testing and trying things, and then you figure out what you don't need to do and what you can do to continue to optimize and improve those dollars spent.
And I think -- I mentioned earlier, we have two different zones that we like geologically and we have two different completion techniques. And so one of the reasons we added two more wells was that we think if we are correct in our thesis about the completion technique, we could actually, hopefully, achieve great results or similar results, but significantly reduce the cost of the well.
Gail Nicholson -- KLR Group -- Analyst
OK, great. Thank you.
Russell Parker -- Chief Executive Officer
Those are 10,000-foot laterals, by the way. I should mention.
Operator
And our next question today comes from Gregg Brody of Bank of America Merrill Lynch. Please, go ahead.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
Good morning, guys. Just two questions for you. The first one, I noticed you made a small acquisition after the quarter was over. Is there any protection associated with that? And is there a net acreage count that we can add?
Russell Parker -- Chief Executive Officer
So that was an incremental piece of the acquisition we made from Carrizo earlier this year. So it's just a little bit of extra interest and some of those same leases. The production that came with it is pretty small. I'll call it, in fact, technically, I think, it's about on the order of about 150, 160 net barrels a day.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
And then is there a net acreage number when you factor in the working interest that we can think about?
Russell Parker -- Chief Executive Officer
It's going to be right on the order of about 2,600 net acres.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
All right. And then just last one on -- Sean covered a lot of the credit questions, but just one -- so I recognize you have a lot of optionality to address the 9.375% of '20. I am just trying to understand what's your flexibility for additional one in an 8 billion and one in a quarter million? Just your view of that today?
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Yes. I think over there is -- we've done a few of the more senior secured tranches, we've got a credit facility basket that today is $2.5 billion roughly, including the one in a quarter. So simple way to think about that is, what are all the tranches that are peri or senior to the one in a quarter. So if you can just run through the quick math, we've have got $500 million of the one in a quarter, 2024, we've got a $630 million RBL first-lien, and then we've got a $1 billion one in an eighth.
So you get to the rough math, roughly $400 million -- $370 million today is exact of kind of incremental senior link capacity.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
And then just along the lines, you mentioned something about structural considerations or as you mentioned structural ways to improve your debt, what does that mean?
Kyle McCuen -- Senior Vice President and Chief Financial Officer
I think Russell was referring to the structural considerations in the Permian as it relates to infrastructure. I don't think I've said anything in regards to structural modifications as it relates to our...
Russell Parker -- Chief Executive Officer
Yes. Let me clarify that. I meant -- by structural, I meant potential JVs, development JVs, those kinds of structures.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
You've been talking about those in the past? All right.
Russell Parker -- Chief Executive Officer
Yes. And by the way just to clarify, Gregg, that was actually over 3,000 net acres that came along with that, a little bit larger number.
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
Thank you.
Operator
And our next question comes from Joshua Gale of Nomura Securities. Please, go ahead.
Joshua Gale -- Nomura Securities -- Analyst
Hey, good morning. Thanks for taking the questions. I guess, Sean and Gregg have asked some of these questions already, but I just want to get a little more clarity on the impact to shut-ins on the second half in the Eagle Ford. It sounds like there's kind of two sources, the EOR expansion and the horizontal development, and I think you had estimated you said, 2,000 barrels a day impact in total.
So just wanted to clarify that was barrels or BOEs?
Russell Parker -- Chief Executive Officer
Net barrels per day.
Joshua Gale -- Nomura Securities -- Analyst
OK. And I don't know if you have these figures handy, but in the 10-K, you disclosed in the Eagle Ford there were 31 gross wells in progress at year-end '17. I was wondering if this is kind of the way to ask the question without getting into commentary in 2019, can you give us an estimate of 2018 year-end DUCs? And then what that number was in the original budget?
Russell Parker -- Chief Executive Officer
So we should probably come in gross DUCs be on the order of 15 to 20 depending upon just how many wells are actually in completion, say, over the end of the year at December 31. So that will be a slight reduction in DUC inventory over the year.
Joshua Gale -- Nomura Securities -- Analyst
OK. And then sort of I just want to ask about one particular area. I noticed that there are three wells being developed in the Maltsberger lease, I think 98, 99 and 102 that require probably three shut-ins, the 100, 101 and 106. And I would guess that the five wells in that particular area that you've brought on recently are probably among the highest in your deal today in terms of single well.
So is that something that was new as part of the revised activity?
Russell Parker -- Chief Executive Officer
Joshua, you do great research.
Joshua Gale -- Nomura Securities -- Analyst
Thanks.
Russell Parker -- Chief Executive Officer
I'll answer your question that way.
Joshua Gale -- Nomura Securities -- Analyst
Appreciate it. Then sort of last one. I just want to go back to some of your earlier commentary on trying to keep the maintenance capital down and stay sort of flat at the oil rates that you're going to be exiting 2018 at. What kind of pricing environment or cost environment would you need to see to have sort of more aspiration to grow from that number?
Russell Parker -- Chief Executive Officer
Well, I think it's not just only a question of cost, but then is a question of A&D activity, what ultimately happens with your inventory because -- and we certainly are running those models out, where we look at, OK, what happens if you increase activity 50%, 100%, drop it by 50%. And so then there does become a question of being able to balance near-term cash flow growth against the long-term depletion of the inventory. So I think we have to keep in mind in consideration, we are very active in the A&D space, but what actually transacts and occurs in that space. So it's really weighing those two things against one another is, OK, look, if we are in a price environment where we're seeing great returns of return and we can bring great cash flow forward, that's something that is definitely we're considering, say, once you're certainly in the $65 and up prize arena, especially with where we are on the margins in that basin.
And then we just have to weigh that against our long-term inventory. That's also, though, why we are engaging in some other projects, like the new zones of the Permian, the horizontal in the Altamont, EOR in the Eagle Ford, and in fact that actually helps us to build inventory, but we need to understand and know the impact of that sooner rather than later, which is why we're engaging in all of this activity. But ultimately, you're right. It gets down to -- the goal is to drive that maintenance capital lower such that at current rates we can actually end up being free cash flow neutral to positive, and then it just becomes an acceleration decision, do we decide to accelerate that capital to bring forward some near-term cash flow, improve the debt metrics, and then utilize one of the other projects that we're working on to continue to deploy capital for the long term.
So we're not ready to make those decisions yet. We're doing everything to set ourselves up to make those decisions wisely and prudently, though.
Joshua Gale -- Nomura Securities -- Analyst
All right. Thank you. That's it for me.
Operator
And our next question comes from Jacob Gomolinski-Ekel of Morgan Stanley. Please, go ahead.
Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst
Hey, good morning, and thanks for squeezing me in here. You mentioned -- I just want to make sure we heard properly that did you mention maintenance CAPEX went from $600 million to $450 million to $500 million? And the reason I am just trying to confirm is because I thought on the Q4 call it was kind of $450 million to $500 million going down to the low 4s. So just trying to get a sense of that change is because we're talking about maintenance on a higher production base compared to what was discussed on the Q4 call or there was something else?
Russell Parker -- Chief Executive Officer
So when I referred to the $600 million, I'm seeking to prior periods, so actually looking back to prior years. When -- on prior calls, I mentioned that we thought we could get the CAPEX or the current kind of burn rate for maintenance capital, say, our current oil rate would be on the order of about $500 million. But right now, with the changes that we're making and with some of the things that we're doing, I think, we have a line of sight to try to work that even further down another $50 million. So maybe there is just a bit of confusion there, but I'll clarify it that way.
Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst
No, that's actually super helpful. And then I know that you've discussed using the A&D market as a lever to improve leverage and the balance sheet overall. Can you just update us on how you're thinking about the A&D market, particularly as we've seen the large BHP package transact? And maybe also how you're thinking about -- I guess, you discussed already a fair amount on the balance sheet and leverage reduction, but if the focus maybe going forward is EBITDA growth, debt reduction or the A&D market or something else?
Russell Parker -- Chief Executive Officer
You bet. So I mean, certainly, it's an interesting time. You have some interesting players and you also have some acres that's -- some acres being actively developed, some acres that's not being actively developed. We're working everything from the small 1,000 or even smaller acre tracks all the way up to multibillion-dollar deals to see what -- and pricing at a place that could be accretive for us.
So again I don't have a deal that I can comment on just yet. We are very actively working on several different fronts on both sides of the equation there.
Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst
OK. Obviously, a multibillion-dollar deal would be transformational, but even maybe something that large or something, let's say, smaller than multibillion, but larger than 1,000 acres. How do you think about -- what's the thought process around financing that?
Russell Parker -- Chief Executive Officer
So if it's -- say, if it's in the $100 million to $250 million size or possibly even bigger, and I'll let Kyle chime in here, too, that's something that we typically would plan on doing on balance sheet. Once you get closer to $1 billion, then we might look at an acquisition co-model unless we are able to also time that with disposition or properties at the same time. That's an ideal scenario for us. That's a really challenging scenario, that means you have to work on a lot of ideas all at once, which all of the fine folks that are working on those projects will tell you, that's why they're working so hard.
But absolutely, I mean, the ultimate goal is to basically bring in acreage, where we think we make our capital more efficient, right, while being -- or kind of rightsizing the inventory for the balance sheet. So -- and we're -- like I said, we're very actively working on both of those fronts. The deals, to get your question on how you would do it, Kyle chime in here, too, but deals up to, say, $500 million on balance sheet once they get over that, we would have to look at some sort of creative structure to make it happen.
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Yes. I would agree with everything Russell laid out there. I mean, the ideal situation is just what we did -- what Russell mentioned back in January and February, where you sell inventory that we weren't get to for a number of years, a long period of time with really no cash flow ascribed to it. I think, we sold it at roughly 15 times debt to EBITDAX, and we use those proceeds to reload or increase our economic inventory, capital-efficient inventory in the Eagle Ford.
But those things are difficult at times exactly, but that's always kind of at the top of the list of how we'd like to fund acquisitions going forward. And certainly, if it's above, we've got some capacity via our RBL and senior link capacity if needed to fund an acquisition of size, say, $500 million. But going north of that, I agree with Russell's comments, we probably do something on the creative side of things and it could be that acquisition co-type structure. So the important thing to note, though is, I think, for us to be successful, we're looking at all the options that run the game because, like Russell said, you got to be active in the market continuously and see what opportunity is attractive and seeing that the company can close on those transactions or those opportunities.
Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst
That's super level. Thank you very much.
Russell Parker -- Chief Executive Officer
Thanks, Jacob.
Operator
And our final question today comes from Maryana Kushnir of Nomura Asset Management. Please, go ahead.
Maryana Kushnir -- Nomura Corporate Research and Asset Management Inc. -- Analyst
Hi. I wanted to clarify one thing about the guidance. Obviously, you discussed the impact of shutting in wells. I was just curious if you're drilling longer laterals and switching to the longer laterals, would that shift also impact the production just basically due to the longer cycle? That's the first clarification that I have.
Russell Parker -- Chief Executive Officer
So the issue that we're dealing with now, we're trying to honestly minimize that impact for the long term, and the way we're minimizing that impact is actually to fill in as much as we can, right now, today all of our leases that are not actually completely filled in. Where we have the most opportunity to drill 15,000-foot laterals for the most part, that acreage is actually out in space. And so I anticipate -- we anticipate that for the longer term, that impact is actually going to be muted and will not be as drastic.
Maryana Kushnir -- Nomura Corporate Research and Asset Management Inc. -- Analyst
OK, all right. But my question was more about the longer cycle of drilling longer laterals versus short laterals rather than -- in addition to the shutting and production. But...
Russell Parker -- Chief Executive Officer
Certainly -- so certainly, the longer laterals do have a longer cycle time, mostly it's on the completion phase. The drilling time does add a piece of it as well, but the completions also add to that cycle time. But if you are -- two things, we -- while it does add cycle time, we still believe we will -- you will achieve a lower F&D and a higher ultimate rate of return by developing the fields with this longest laterals as are practical before you lose or get to a point of diminishing returns in terms of recovery per dollar spent. But then on your -- relative to your second question, yes, if we had long laterals offsetting short wells that are on production that would cause a bigger impact, but what we've done with our drilling schedule as we accelerate activity is we're trying to take as much as that hit early term, near term and get it out of the way and then effectively as much as practical, you can't do this 100% of the time, if you will, mow the lawn in 2019 and beyond.
Maryana Kushnir -- Nomura Corporate Research and Asset Management Inc. -- Analyst
OK. Understand. And then regarding the comment about trying to shave off $50 million of the maintenance capital, I just wanted to clarify the $475 million to $500 million that you were stating before, that's the level of maintenance capital you see in the business currently, did I get that right?
Russell Parker -- Chief Executive Officer
So -- yes, currently, we see it is probably around $500 million. However, with all of the changes that we're making, we see a line of sight to get that down in 2019 to $450 million or hopefully even lower.
Maryana Kushnir -- Nomura Corporate Research and Asset Management Inc. -- Analyst
OK. OK, thank you.
Operator
And this concludes our question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.
Russell Parker -- Chief Executive Officer
Thank you very much. Well, we appreciative everybody's time and interest. We are certainly excited about the long-term potential for the value of our assets, value of the company. We believe we've got a great execution, operational and technical and entire team, really, of professionals that are executing upon these ideas, all focused on creating a long-term value growth.
That's really the focus of the company. We look at how we spend each and every dollar, and how we can maximize that dollar to realize the best return for the long term for us, as well as all of the shareholders. So we appreciate, again, everyone's time and interest this morning. And look forward to realizing some more positive results in the future quarters to come.
So thank you very much.
Operator
[Operator signoff]
Duration: 61 minutes
Call Participants:
Jordan Strauss -- Manager of Investor Relations
Russell Parker -- Chief Executive Officer
Kyle McCuen -- Senior Vice President and Chief Financial Officer
Scott Hanold -- RBC Capital Markets -- Analyst
Joe Allman -- Baird -- Analyst
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Sean Sneeden -- Guggenheim Securities -- Analyst
Gail Nicholson -- KLR Group -- Analyst
Gregg Brody -- Bank of America Merrill Lynch -- Analyst
Joshua Gale -- Nomura Securities -- Analyst
Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst
Maryana Kushnir -- Nomura Corporate Research and Asset Management -- Analyst
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