Exhibit 99.1
EP Energy Corporation [EPE]
Q2 2018 Results Conference Call
Friday, August 10, 2018 10:00 AM
Company Participants:
Jordan Strauss, Manager of Investor Relations
Russell Parker, President and Chief Executive Officer
Kyle McCuen, SVP, Chief Financial Officer
Analysts:
Scott Hanold, RBC Capital Markets
Joe Allman, Baird
Derrick Whitfield, Stifel Nicolaus
Sean Sneeden, Guggenheim Securities
Gail Nicholson, KLR Group
Gregg Brody, Bank of America Merrill Lynch
Joshua Gale, Nomura Securities
Jacob Gomolinski-Ekel, Morgan Stanley
Maryana Kushnir, Nomura Asset Management
Presentation
Operator: Good morning, and welcome to the EP Energy second quarter 2018 results conference call. (Operator Instructions). After today’s presentation, there will be an opportunity to ask questions. (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: 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 the supplemental presentation that we published yesterday. The earnings release and presentation are available on the Investor section of our website, epenergy.com.
I’d like to remind everyone that on today’s call, we discuss forward-looking statements and certain non-GAAP financial measures. We encourage you to read our full disclosures on forward-looking statement and GAAP reconciliations that 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: Thank you, Jordan, and 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 9 months. And we are 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. And 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 offset. 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 an EUR basis, but really a dollar 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 happy to talk more about that during the question-and-answer session.
So the next thing I want 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, our current pricing structure.
In addition, we’re seeing quite a significant improvement, as demonstrated by the material, in our well results, and with all the changes in the designs that we’ve been making relative to our completion style.
So with that, there’s a good and a short-term impact as well. When you accelerate activity, you’re going to have to shut in your immediately offset well. So we’re going to see a little bit of an impact to that in the second half of the year. However, we think, and we know, all of this activity is actually going to finish 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 had 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, our early-term results, on those horizontal wells in the Altamont, as well as our EOR filings.
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’re trying a lot of things. We’re now letting all these experiments take some — we’re giving them some time to show their value impact and show the results. And in short, 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 these 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?
Kyle McCuen: 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, so a significant increase from the last 3 quarters. And our cast costs continued 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 acquisition of properties we made in 2016. Absent that charge, our G&A would’ve been approximately $0.40 per barrel lower.
Our debt maturity profile significantly improved. In May, we successful extended our reserve base loan facility to November 2021. And the refinancing significantly cleared our runway, allowing us valuable time to execute on our new project and evaluate A&D options to improve our financial position.
Liquidity 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 3 million barrels of 3-way collars with a floor price of approximately $60 and a ceiling of $70 WTI. These hedges now protect over 50% of our 2019 oil production using the midpoint of our 2018 oil production estimate, while retaining attractive upside exposure.
You’ll also note in our slide deck, we layered in a million barrels of 2019 mid-Cush swaps at WTI minus [650] and we’ll continue to monitor markets to potentially layer in more 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 filing, 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 non-public 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’re now ready to take questions. So I’ll turn it over to you, Operator.
Questions & Answers
Operator: Thank you. We will now begin the question-and-answer session. (Operator Instructions). Scott Hanold, RBC Capital Markets.
Scott Hanold: 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 of highlighted that that’s 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: 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, 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 it’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.
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, 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 well. 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 EOR per dollar spend — or F&D rather, and rate of return, we see an improvement and we showed that graphically. We actually took the June economic Boes, divided it by the dollars spent per 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 are also completed in the quarter in which we actually dropped some pounds for foot, but increased the pounds per cluster. So these were actually cheaper wells; they were less expensive wells, and they’re performing pretty much in line with their immediate offsets. And the key is knowing how those wells were completed and how much money is 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 is how we judge all of our projects as well. So here on this group of wells, you can see the well performance is similar, but the well performance relative to the dollar spent is about 20% better, actually a little bit more than 20% better on this group of wells.
So what does that means? So I’ll speak to this part of the equation, just the completion design. What that means is that our capital is becoming more efficient and what — 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 2017. 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 the primary focus is certainly completion design.
The 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. The really — we think that is probably our best opportunity to have very efficient capital for the long-term, but it is — we’re in the early stages, very early stages, of that project.
You’d also ask Scott about longer laterals. So there’s a large portion of our field 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 wells. And there’s 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 — we actually took a core in that area earlier this year and we’re analyzing it now to make sure we can tailor in our completion designs.
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 correctly, or is not all communicating back into the wellbore, then you can experience those issues. And so that’s why we felt that important to go ahead and start trying a couple of different techniques on our longer laterals, get a couple of them down. We drilled record wells for 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’ve got — in terms of the amount of acres that we 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 EOR, the goal of course, is to continue to work that number down, down, down. As I said, we’re able to maintain our EBITDA and actually throw off more free cash flow after CapEx. So a long-winded answer but hopefully, that tells you what you needed there, Scott.
Scott Hanold: Yes, and I guess there’s just one component that — just a little bit more color. The EOR project seems like this is something that’s going to take a little bit of time. Some of this development patterns and the longer laterals may be something we could start seeing the benefit in 2019. But again, from our seats, certainly on the 2018 numbers, production is a little bit softer; CapEx a little bit higher.
But in theory, what will this do to 2019? Should we expect better efficiency in 2019 based on what you are doing here in the back half of 2018 if you can quantify that? I’m trying to avoid — force you to try to give us 2019 guidance, but can you just give us a little bit of color there?
Russell Parker: That’s right. Yes, we’re not ready to do — to guide for 2019, but all of these decisions are done, are made in the guise of exactly what you said there, Scott. And certainly from a timing standpoint, look, EOR is going to have a very small impact on 2019; 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 2019.
And so probably the best way I could — 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 $225 million. But we feel like developing the field this way, in-filling as quickly as we can to our offsets, so basically [mowing the lawn], making sure that
we’re optimizing our completion design, we should end up shaving off — ideally, our goal is $50-plus million dollars of maintenance capital. So that’s probably the best way I could guide you.
Now, in terms of what happens in 2019, of course, we’ll have to look at prevailing prices and see what happens with our inventory, what acquisitions and divestures that you make in order to actually set a 2019 budget. But 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: Okay. That’s definitely helpful. And as a follow-up question, you all have initiated the 30 EOR project; you’re drilling a second. There are two more horizontal wells in the Altamont. It seems like it — I would’ve 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, boy, this is the right thing to do and we need to go forward with this?
Russell Parker: Absolutely. So I’ll speak about the horizontal wells in the Altamont. As we dug through the geology and looked at all the activity in the [basin], and looked 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 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’d like to try, but of course, we need to normalize that result. So that’s why we added two more wells into the project for this year.
On the EOR, yes, we are encouraged by what we see. We think we are able to impact a large portion of our reservoir, a larger portion of our reservoir than what we originally anticipated, with our first pilot and so we’re encouraged by that. We are 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, 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 inning, 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 2019, 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: All right. I appreciate that. Thank you.
Operator: Joe Allman of Baird. Please go ahead.
Joe Allman: 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 of size is May 2020. So what are your thoughts on how you handle that?
Kyle McCuen: Hey, Joe. Yes, 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 2 years away. Probably we’ll obviously deal with that sometime before it’s 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: Got you, very helpful. And then Russell, in terms of the portfolio composition, I know you’ve done a lot of testing so far. It’s still pretty much in the middle of the year. Any conclusions about where you think the portfolio composition will reside over time?
Russell Parker: 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 before we like to call it, and say here’s what we think we’re doing economically from an F&D rate of return standpoint in terms of just how successful the wells are. So we need a little bit more time with that. It’ll be the end of the year before we know more about the horizontal potential at least just 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.
Joe Allman: That’s helpful.
Russell Parker: Now, in terms of the — and you may have been — or were you referring more to the A&D market?
Joe Allman: Yes, right now, you’ve got 3 assets and you’ve got a lot of debt. So you got to kind of figure out what to do, and so I’m thinking about both actually.
Russell Parker: Okay. All right. Well, fair. Yes, so we are very active in that space looking for certainly things that are accretive to bolt on. Now, in terms of the divestiture process, we have made one small divestiture in the last 9 months. We don’t have anything actively marketed right now.
Certainly we do have a lot of debt, and I’ve mentioned this before. Surprisingly, even though I say it publicly, people don’t just walk into 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 kind of structural options as well to help improve our debt metrics with time; certainly making the capital more efficient, and 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 even faster pace, and so that’s a major focus of the Company. We are very active in that space; have nothing to transact or 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. That’s probably the best way I can say that.
Joe Allman: Yes, that’s helpful. And then in terms of the Permian, after you finish the 3Q completions, I think you’re basically shutting down that program. My assumption would be that the first part of 2019, there would be little or no activity in the Permian as well, especially because you’ve got — your base hedges are not quite as good in 2019 as they are in 2018. Is that a fair assumption, that the first part of 2019, probably very little or no activity in the Permian?
Russell Parker: I don’t know if I — I wouldn’t say no activity and we’re actually working on — we’ve got our base production hedged. It’s the incremental — if we were to grow the production quickly, just like anybody else in the Permian, you’d be dealing with spot bases, which could be painful. We are working on improving that position for the long term, and we think there’s obviously some structural things that are happening in the basin that everybody is aware of, that will help to improve that as well.
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, that there would be no activity. There may be less activity than the Eagle Ford, but we’ll just have to — part of that is just scope and scale, but we’ll — as we get closer to Q1, we’ll certainly have more certainty on that.
Joe Allman: Okay, 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: No conclusions yet. The wells are just now — some of them have just now been coming on line. 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 get wells at least 90 days or more if we can, performance, before we start to talk about results.
Joe Allman: Okay, that’s helpful. And lastly, on the Eagle Ford, slide 10 and 11, my conclusion is that just I look at the slides, that increase completion design is better, right, than the decrease completion design even on a Boe per dollar spent basis. And are you trying to say that even if you decrease the completion design, 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: Well, it’s really that we don’t think one size fits all. We think that you have to engineer each pad and look at each situation. And in some instances, depending upon where the wells are landed, that particular zone, and how they’re spaced, 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 as little — as few dollars as you can to maximize the recovery on your entire lease, right?
So in some cases, depending upon — and part of it depends upon how the prior wells have been drilled and how they are spaced, and you have to work with that. So the key there is just looking at what is the situation and how do I optimize my remaining dollars to get the best economic recovery for the dollar spent.
But part of what we wanted to point out on the wells with the smaller completion design is if someone would say — just go to public data and pull the well results, you might look at that and say, okay, well, they managed to match the 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: Got it. Okay, very helpful. Thank you.
Operator: Derrick Whitfield of Stifel.
Derrick Whitfield: With regard to your second half guidance, could you help us better shape Q3 and Q4 production estimates? Specifically, with well guidance, does 5% down in Q3 and 5% up in Q4 seem reasonable based on the timing of your activities?
Kyle McCuen: Definitely Q4 is going to be towards the higher side of the guidance, and probably Q3 is going to be towards the lower side. So maybe a little bit flat and then building into a ramp towards the end of the year.
Derrick Whitfield: Got it, very helpful. And then Russ, going back to your comments on the Eagle Ford, what are your pre-drill expectations for the 15,000-foot laterals? Are you specifically expecting, with 2 times the lateral, you get 1.7 [ton] 5 times the EUR at 1.5 times the cost?
Russell Parker: 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 in how the well 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, and so on and so forth. It’s at least on that order of magnitude to develop the same amount of reserve.
So if we think back to even these plots we showed here, what that’s doing is just allowing us to develop more economic Boes, right, for the dollar spent. It just makes our capital that much more efficient, which helps us get our maintenance capital down and ultimately, grows long-term value for the Company.
But 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 their immediate offsets and then build the plans out for the long term.
Derrick Whitfield: Makes sense. And then lastly, from a [spin] 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 derisk following the 3 pilots?
Russell Parker: The plan is actually to derisk pretty much all of it. So there’s — we are going to cover basically from our oiliest interval to our gassiest interval, and to determine the impact as you change fluid type and pressure.
Derrick Whitfield: Very helpful. Thanks for taking my questions.
Operator: Sean Sneeden of Guggenheim.
Sean Sneeden: Maybe just first, could you just, Russell, brief us on the prior production guidance in the current — I know you kind of outlined the 500 on the sliding scale. Is the balance all just shut-ins kind of temporarily, or how should we think about that?
Russell Parker: 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 have to make a choice, right?
You have to decide, well, do I go complete wells 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.
We found there’s two methods to really — or three methods, I’ll say, to really making sure that you develop all the rock appropriately and mitigate frac interference. But first and foremost is to complete the in-fill wells as close in time as you can to the parent. That’s the most important thing.
Next, we have a process to both shut in and then pump in and hold pressure on the offset wells while we’re completing the new wells. And we’ve found that with that, we were able to mitigate pretty much any damage. As a matter of fact, our in-fill wells in the first quarter were outperforming their offset parent well. 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 dollar spent over the long term, and the best thing to make sure that you are recovering the most amount of hydrocarbon (inaudible) 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 drilled wells out in space, we could have a lot more near-term production, and possibly, if they were short, spend less capital.
However, we would be setting ourselves up for a very rough 2019 because the longer you wait between the parent well and your child well or your in-fill well, the more likely it is that your in-fill 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 have to kind of walk yourself through the entire decision-making process. It’s, okay, 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, less accelerated activity. Then you have two choices as to how you accelerate activity — drill wells in space or in-fill your recent offsets. And we feel like the best thing to do for the long term is to in-fill a recent offset.
However, that does mean we’re going to have a near-term impact on production, and so that’s really the crux of it there. We do have a little bit of an impact from the sliding-scale royalty. And then, of course, there is also a little bit of near-term impact from EOR because in order to engage in that project, we are shutting in the wells involved, such that they will — such that the reservoir can build pressure around the wellbore.
Sean Sneeden: Got it. That makes sense. And just to put some numbers around it, like the quick math would kind of suggest around maybe 2,000 a day or something at the midpoint. Is that kind of how we should think about shut-ins? And should we think about those volumes kind of returning in 2019 and beyond once the completions finish up?
Russell Parker: I think your math skills are just fine.
Sean Sneeden: Perfect; I appreciate that. And then just two quick ones for Kyle. I appreciate your — the commentary on free cash flow neutrality in your second half. Is that the goal or target really kind of going forward, that you’re trying to manage like at least EBITDA to kind of interest [burden] plus CapEx? Is that how you guys are kind of thinking about it?
Kyle McCuen: Certainly, that that’s been a stated 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 — our cash — or I’m sorry — EBITDAX, availability for 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 will have to weigh the merits to 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 will 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 are increasing capital versus our previous guidance. That’s all through the purposes of unlocking value.
Sean Sneeden: Got it. That’s helpful.
Russell Parker: And let me tack on what Kyle said too. Again, the technical work that we’re doing this year is all under the guise 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 off some cash flow to 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: That makes sense. And then Kyle, it looked like you guys repurchased some of the unsecureds, I guess, specifically some of the [22 to 23]. What was the driver there? And can you just remind us on your ability to do more of the market repurchases?
Kyle McCuen: Sure, yes. So early in the second quarter, we did conduct some open-market debt repurchases. I think they were, in my view, done at 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 will 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 category (inaudible) that allow us to conduct those repurchases. And it just varies, Sean, by tranche. Rather than get into the minutiae of the basket for each tranche, I’d say it’s well north of what we did in the second quarter.
Sean Sneeden: Okay, 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: They are, but they don’t have a rate impact except for just the 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’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 even to our current Q4.
Sean Sneeden: Got it. That’s very helpful. Thank you very much.
Operator: Gail Nicholson of KLR Group.
Gail Nicholson: Just quickly, in regards to the sliding royalty agreement with that university land, has there been any discussion with [them] in regards to the widening of the bases, maybe oscillating that agreement maybe in 2019, not to be linked to WTI, but be linked to WTI less basis? I just was curious if you guys had those discussions.
Russell Parker: So hard to comment because we’re actually in the middle of discussions around a number of things, but the concept you mention is — does not fall on deaf ears. Maybe I���ll say it that way. But we’re actively working that.
Gail Nicholson: Okay, perfect. And then turning to the Altamont, what are the costs for the horizontals? And then are those horizontal wells that [are] being added, are those falling under your JV agreement with Tesoro, or are those 100% EPE wells?
Russell Parker: 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, you usually are 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.
As a matter of fact, that’s — I mentioned earlier, we have 2 different zones that we like geologically and we have 2 different completion techniques. And so one of the reasons we added 2 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: Okay, great. Thank you.
Russell Parker: Those are 10,000-foot laterals by the way, I should mention.
Operator: Gregg Brody of Bank of America Merrill Lynch.
Gregg Brody: Just two questions for you. The first one, I notice 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: 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; in fact, [technically], I think it’s about on the order of about 150 to 160 net barrels a day.
Gregg Brody: And then is there a net acres number when you factor in the working interest that we can think about?
Russell Parker: It’s going to be right on the order — let’s see, it’s going to be right on the order of about 2,600 net acres.
Gregg Brody: Right. And then just last one on — Sean covered a lot of the credit questions, but just one. So I recognized you’ve got lot of optionality to address the (inaudible) rates in 2020. I’m just trying to understand what’s your flexibility for additional [1 1/8] lien and [1 1/4] lien, just your view of that today?
Kyle McCuen: Yes, I think there’s — within a few of the more senior secured tranches, we’ve got a credit facility basket that today is $2.5 billion roughly including the [1 1/4]s. So the simple way to think about it is what are all the tranches that are pari or senior to the [1 1/4]. So if you just run through the quick math, we’ve got 500 of the 1 1/4; 2024 we’ve got a $630 million RBL first lien. And then we’ve got a $1 billion 1 1/8. So you get the rough math, roughly 400 — $370 million to exact of kind of incremental senior lien capacity.
Gregg Brody: And then just one more — you mentioned something about structural considerations or structural ways to improve your debt. What does that mean?
Kyle McCuen: I think Russell was referring to the structural considerations in the Permian as it relates to infrastructure. I don’t think I said anything in regards to structural modifications as it relates to our —
Russell Parker: Yes, let me clarify. I meant — by structural I meant potential JVs, development JVs, those kinds of structures.
Gregg Brody: You’ve been talking about those in the past. All right, that’s it for me guys.
Kyle McCuen: Yes. 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: Thank you.
Operator: Joshua Gale, Nomura Securities.
Joshua Gale: I guess Sean and Gregg have asked some of these questions already, but I just wanted to get a little more clarity on the impact of 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. I think you’d had estimated — you said 2,000 barrels a day impact in total. I just wanted to clarify if that was barrels or Boes?
Kyle McCuen: Net barrels per day.
Joshua Gale: Okay. 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 2017. I was wondering if — just 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?
Kyle McCuen: So we should probably come in — gross DUCs would 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 would be a slight reduction in DUC inventory over the year.
Joshua Gale: Okay. And then I just wanted to ask about one particular area. I noticed that there are 3 wells being developed on the Maltsberger lease — I think 98, 99 and 102 — that require probably 3 shut-ins — 100, 101 and 106. And I’d guess that the 5 wells in that particular area that you brought on recently are probably among the highest in your field today in terms of a single well. So is that something that was new as part of the revised activity?
Russell Parker: Joshua, you do great research.
Joshua Gale: Thanks.
Russell Parker: I’ll answer your question that way. (Laughter).
Joshua Gale: I appreciate it. The 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 existing 2018 at. What kind of pricing environment or cost environment would you need to see to have more aspirations to grow from that number?
Russell Parker: Well, I think it’s not just only a question of cost, but then it’s a question of A&D activity, and what ultimately happens with your inventory because — and we certainly are running those models out where we look at, okay, 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 and 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.
It’s, okay, look, if we are in a price environment where we’re seeing great rates of return, and we can bring cash flow forward, that’s something that is definitely we are considering, say, once you’re certainly in the 65 and up price arena, especially with where we are in the margin 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 horizontals in the Altamont, EOR and the Eagle Ford. In effect, 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 and (inaudible) 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: All right. Thank you. That’s it for me.
Operator: Jacob Gomolinski-Ekel of Morgan Stanley.
Jacob Gomolinski-Ekel: You mentioned — I just to make sure we heard properly. Did you mention maintenance CapEx went from $600 million to $450 million to $500 million? And the reason I’m 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 because we’re talking about maintenance on a higher production base compared to what was discussed on the Q4 call or something else.
Kyle McCuen: So when I refer to the $600 million, I’m speaking to prior periods, so actually looking back to prior years. On prior calls, I had mentioned that we thought we could get the CapEx or the current kind of burn rate for maintenance capital, say, at our current oil rate would be on the order of about $500 million. Right now, with the changes that we’re making and 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’s just a bit of confusion there, but I’ll clarify it that way.
Jacob Gomolinski-Ekel: No, that’s actually super-helpful. Thank you. 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 see in 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 leverage reduction, but if the focus maybe going forward is EBITDA growth, debt reduction or the A&D market or something else?
Russell Parker: You bet. So certainly, it’s an interesting time. You have some interesting players and you also have some acreage 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 tracts all the way up to multi-billion-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 though.
Jacob Gomolinski-Ekel: Okay. Obviously a multi-billion-dollar deal would be transformational, but even maybe something that large or something, let’s say, smaller than multi-billion, but larger than 1,000 acres. How do you think about — what’s the thought process around financing that?
Russell Parker: So, 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 code model unless we are able to also time that with a disposition of 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 where the (inaudible) are.
But absolutely, the ultimate goal is to basically bring in acreage where we think we make our capital more efficient, right, while being — or kind of right-sizing the inventory for the balance sheet. And we’re — like I said, we’re very actively working on both of those fronts. The deal — to get to 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: Yes, I’d agree with everything Russell laid out there. The ideal situation is just what we did, what Russell mentioned, back in January and February, where you sell inventory that we weren’t going to get to for a number of years, a long period of time with really no cash flows ascribed to it. I think we sold that roughly 15 times debt to EBITDAX, and we used those proceeds to reload or increase our economic inventory, capital-efficient inventory, in the Eagle Ford, but those things are difficult to time exactly. But that’s always kind of at the top of the list of how we’d like to fund the acquisitions going forward.
And certainly, if it’s above, we’ve got some capacity, the RBL and senior lien capacity, if needed, to fund an acquisition of size, say, $500 million. But going north of that, I agree with Russell’s comments, we’d probably do something on the creative side of things and it could be that acquisition code-type structure.
So the important thing to note though is, I think for us to be successful, we’re looking at all the options from — that run the gamut, 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 and those opportunities.
Jacob Gomolinski-Ekel: That’s super-helpful. Thank you very much.
Operator: Maryana Kushnir of Nomura Asset Management.
Maryana Kushnir: 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: So the issue that we are dealing with now, we are 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.
Maryana Kushnir: Okay.
Russell Parker: 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: Okay. 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-in production but —
Russell Parker: Certainly, the longer laterals do have a longer cycle time. Mostly 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. While it does add cycle time, we still believe we will achieve a lower F&D and a higher ultimate rate of return; but developed in the field with as long 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 shut-in 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 accelerated activities, we’re trying to take as much of 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: Okay, 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: So yes, currently, we see it as 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: Okay. Okay. Thank you.
Operator: And this concludes our question-and-answer session. I would like to turn the conference back over to the management team for any final remarks.
Russell Parker: Thank you very much. Well, we appreciate everybody’s time and interest. We are certainly excited about the long-term potential for the value of our assets, the value of the Company. We believe we’ve got a great executional, operational and technical and entire team, really, of professionals that are executing upon these ideas, all focused on creating 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 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: And thank you, sir. This concludes our conference call today. We thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day.
