Exhibit 99.1

EP Energy Corporation [EPE]

Q1 2018 Results Conference Call

Wednesday, May 9, 2018 12:00 PM

Company Participants:

Bill Baerg; Director of Investor Relations

Russell Parker; President and Chief Executive Officer

Kyle McCuen; Chief Financial Officer

Analysts:

Scott Hanold; RBC Capital Markets.

Brian Corales; Johnson Rice & Company

Joe Allman; Baird

Phillips Johnston; Capital One Securities

Sean Sneeden; Guggenheim Securities

Joshua Gale; Nomura Securities

Gail Nicholson; KLR Group

Presentation

Operator:  Good day, and welcome to the EP Energy first-quarter 2018 results conference call. (Operator Instructions) Please note this event is being recorded.

At this time I would like to turn the conference over to Bill Baerg, Director of Investor Relations. Please go ahead, sir.

Bill Baerg: Thank you, Denise, and good morning, everyone. Thank you for joining our call. Today our speaker will be Russell Parker, President and Chief Executive Officer of EP Energy. Also joining us is Kyle McCuen, our Chief Financial Officer.

Yesterday we filed our first-quarter press release that included non-GAAP reconciliations and other relevant information. In addition to our press release I’d like to remind everyone that you can find a brief presentation with highlights of our first-quarter 2018 results in the Investor Center section of our website.

On our call today, we’ll make a reference to certain non-GAAP financial measures we regularly use in measuring the Company’s financial performance. Reconciliations of such non-GAAP financial measures with comparable financial measures calculated in accordance with GAAP are contained at the end of the Company’s press release.

As a reminder, certain statements included in this morning’s presentation may be forward-looking and reflect the Company’s current expectations or forecast of future events based on the information that is now available. EP Energy does not assume any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

And with that, I’ll turn the call over to Russell.  Russell?

Russell Parker: Thank you, Bill, and good morning, everyone. This is Russell Parker, CEO of EP Energy. I want to thank everyone for their participation on the call today, your interest in the Company and your continued support.

It is a very, very exciting time to be at EP and be associated with the Company. We have initiated several new projects. We have quite a lot of knobs turning in the Company right now and we’re going to get to those later in the call. You also saw quite a bit of material yesterday published on that as well.

But all in all, I wanted to remind everybody and convey that spirit, that it’s a very, very exciting time. There’s a lot of collaboration happening in the Company that’s leading to cost reductions. It’s leading to action and execution between the field office and the Houston office and throughout the entire team. And it’s just very exciting to be a part of, very exciting to see.

And so I definitely also want to take a moment and thank our employees and thank the team that’s involved. We wouldn’t have our successes and our improvements without them. That’s certainly for sure.

So on the quarter, and hopefully everyone saw the materials. We won’t be walking you through them today but hope you saw the slide deck that’s on our website and was posted in the press release as well. I’m going to speak for about five minutes and then we’ll open the call up for questions. We want to use this time as best we can to answer all of your questions about the Company as best we can.

So the short answer is, quarter over quarter, oil rate is up. We’re guiding further up for Q2. As many have commented and noticed, our CapEx was below what we had guided to. We are obviously frontloaded on our CapEx for the year. Two reasons for that. One, the bulk of the money that’s going to be spent on our new projects — so huff ‘n puff, saltwater disposal systems, horizontal wells in the Altamont — the bulk of that CapEx is going to be spent in the first two quarters.

And then the second reason is that the (inaudible) impact will really come into play in the second half of the year in terms of the amount of net CapEx that we’re going to deploy in the Company. So we are definitely frontloaded on our CapEx this year.

Nonetheless, we did come in below expectations for the first quarter and actually completed more wells than we thought we would in the first quarter, so that’s good to see.

We are keeping our rig guidance the same for the year at this point. One thing I want to mention to everyone on the call and make sure you’re aware, when our guidance was originally set and plans were made, the anticipation was a lower prevailing oil price. At current oil prices for Q2, Q3 and Q4, our sliding scale royalty agreement in the Permian comes into play. And so, as a result, we’ll actually be losing about 800 or so net barrels a day, almost 1,000, and then about

1,800 to 2,000 net BOEs per day from the impact of that sliding scale royalty, basically going from 3/8 to 1/4 — or, I’m sorry, 3/16 to 1/4.

And so while we’re maintaining flat guidance for the year, in effect it is a guidance up, if you will, because the original plans and the original guidance were not made with that calculation in mind, because of course we were not anticipating current oil price being where it is. So, luckily, the oil price benefits us as well as it does our competitors, so that’s a good thing. But I did want to make that point early and make that point clear, that we’re losing about that 800 barrels of oil, 1,700 to 1,800 BOEs per day in Q2, Q3 and Q4 average because of that impact.

Couple other things that I’d like to mention. We have had some great success in cost reductions, mostly by design. One of the best examples that we can bring up is actually in the Permian, where we have the same proppant loading in our wells completed in Q3 as we do in Q1. However it was a different design, different cluster spacing, different pounds per cluster. That wasn’t the cause of the cost savings, but it was the same proppant loading between those two designs.

The key and the point of that is that we were able to shave about $400,000, or almost 8%, about 400 — or almost about 8% of the well cost off. And that was by a combination of a number of things. One, using our natural gas frac fleet, which realizes some savings, one on the lack of diesel fuel and using our field gas. The next is our improved run times and improved stage count per day is actually reducing our net costs per stage per day.

The next place we were able to save some money in the Permian — and we’re doing some of this in the Eagle Ford as well — we’ve taken over our flow-backs internally. And then the production team in the field has taken over the drill-outs and the [tube-ups] of those wells. And so basically through that synergy of efforts we were able to shave costs quarter over quarter. So that’s very exciting to see.

Now, we’ve seen cost reductions in the Eagle Ford as well. However, it’s a little bit more difficult to compare because there the proppant loading has varied widely. So we don’t have a perfect example for you, same proppant loading to same proppant loading. But we’ve certainly seen some of those same cost reductions. And, in addition, we will be moving that natural gas frac fleet down to the Eagle Ford in the middle of Q2. So some of the savings that we realized because of the utilization of that crew and that technology we’re going to move to the Eagle Ford and utilize that as we go throughout the rest of the year.

So we’ve been very pleased and very proud of those cost reductions and the ability of our operations team to not only circumvent the pressure of service cost inflation, but actually cause some real savings versus where the company used to be.

Did want to take a minute to mention parent/child interference. We’re doing quite a lot of work on this subject right now. We’ve had good results thus far and we’re trying to improve those results even further. We are now using what’s called FMI logs to try to map and understand where induced fractures sit and infill wells or children wells and avoid that part of the lateral when we complete those wells, thereby reducing ultimate costs. You do drive the cost of drilling

the well up but you actually reduce the cost of a completion enough that you can reduce the cost of the well. And we think early on we potentially are seeing better stimulation results.

So that testing is very, very early, but did want to let everyone know that most of the wells we’ve completed, in the Eagle Ford certainly, have been children wells and for the most part they are either on par or in some cases actually slightly better than their immediate offset parent. So that’s been very, very exciting to see. Again, results are early, so we want to do some more testing and see what else we can do to improve that relationship going forward. But very exciting to see.

Last thing I wanted to touch on was just action, some further action in the Company. We have initiated our first huff ‘n puff pilot. It’s underway today. So we are in the injection cycle right now. And we are currently drilling our first horizontal well in the Altamont. So both of those projects are very exciting. We think they could be game changers in terms of unlocking value.

And certainly to a lesser extent, but along the same lines, we also have installed a permanent water recycling facility in the Permian such that we are able to re-use our produced water for stimulating future wells. So that’s exciting to have that in place. We think we’ll realize not only a great deal of LOE savings but also a good bit of CapEx savings through the year by using that recycled water facility.

So those are my opening comments. That’s what I wanted to — key points I wanted to make to you, make for everyone on the call today to get the call started. With that, I’ll turn it over to Bill and questions.

Bill Baerg: Operator, could you go ahead and open the lines? We’d appreciate that.

Questions & Answers:

Operator:  We will now begin the question-and-answer session. (Operator Instructions) Scott Hanold; RBC Capital Markets.

Scott Hanold: Congratulations on the quarter. It looks like a lot of things are moving in the right direction. Could you discuss a little bit about the move of the drilling JV from the Permian to the Eagle Ford? How did that come about? Was that something that — an initiative you all looked to do? Or was it your partner that requested that? And what are, I guess, the implications of that? What does that mean?

Russell Parker: You bet. So it was really an initiative on both ends. The Company is deploying more capital in the Eagle Ford this year. So in order for our partner to deploy capital, which is certainly one of their goals, it was going to become difficult to do that at a pace they were really interested in if it was Permian only. So from that standpoint it made sense.

And the other issue — and I have talked about this a little bit in the past as well. We feel there’s quite a few things that we wanted to try in the Permian that had not been tried yet. We think the

Southern Midland Basin is a little bit less mature in terms of all the different zones that are potential there to develop. And so we are testing those right now, the lower end of the Wolfcamp as well as zones above and below the Wolfcamp. And we’d like to see the results of that. And then after we see the results of that, basically go back to development mode, but development mode with better information, new information. And we think that that may change our investment thesis in terms of what you’d want to develop first. So given that and given where that state is, it didn’t make sense to put the hammer down, if you will, on capital deployment just yet.

And then the good news is the Eagle Ford is a little bit more mature in terms of completion design, landing intervals and the knowledge there. And then we are accelerating our capital there in 2018 versus 2017. So in order for our drillco partner to participate, that made the most sense, to switch the partnership there. And it’s basically similar terms. We’ve just changed the acreage. Instead of it being in the Permian it’s now in the Eagle Ford.

Now I will say the option to have further drillcos in the Permian, or the Altamont or anywhere, are not off the table. That’s not the issue at all. That’s not the consideration. It’s really more of an issue for us internally as to all of the things that we want to continue to try to unlock value, and then continue to reinvest further once we have that knowledge.

Scott Hanold: Okay. Understood. Thanks for that. And on this huff ‘n puff test that you all initiated, when do you think you’re going to start seeing responses from that, or at least what should the market expect to hear from you? What is — how do you plan to present the results? What should we sort of gear sort of for a range of expectations?

Russell Parker: Absolutely. So we really think it’s going to take the better part of the year to get a good handle on the impact of that first pilot. We’re also attempting — hopefully we’ll have actually a second pilot in, at least installed, before the end of the year. And we’re going to try to test two different parts of our acreage, where you could have two different value implications by utilization of the technique.

So as we get further along in the year we’ll have better updates. The process itself takes about, at least for the pace that we’re moving, it takes about 45 to 60 days on each cycle. And we’d like to see a couple of cycles before really advising to what we think the potential could be. But nonetheless, certainly EOG’s had the strongest results and has had the most prolific utilization of the technology thus far. It looks like it’s there. The key is just how big is the impact and logistically how do you solve it, because it does become basically a big facilities and logistics exercise.

Scott Hanold: Yes. Are you all aware of what response EOG has seen from what they’ve done? Are you (inaudible) —

Russell Parker: Oh, absolutely. As a matter of fact, the best pilot they have is about 10 miles away from us in terms of response.

Scott Hanold: Okay. Are you willing to share some of those to give us sort of a gauge?

Russell Parker:  Well, probably everyone has read the RSEG reports, the third-party consulting report that’s done a nice study on huff ‘n puff. We’ve done our own internal studies. I don’t think RSEG is off base based on what we know today.

Scott Hanold: Got it.

Russell Parker: So there you go.

Scott Hanold: Fair enough. And one last thing, on hedges, given the upward movement in oil prices and I guess over the last couple of years you guys have been very proactive about putting hedges in there to help protect the balance sheet, what are your plans at this point? I mean, ‘19 is a little bit less hedged. So if you could give some color on that as well as the basis hedge.

Kyle McCuen: Scott, this is Kyle. Good questions. We have made progress on the hedging front within the quarter. I think we’ve moved from 10% at the time of our last call to roughly 25 to 30% today. So you can expect us to be — continue to leg into 2019. As we get to the end of the year I wouldn’t be surprised if we’re somewhere around 75% around oil.

And then on the basis we’re set up really well I think. I give credit to the marketing team, Dennis Price and his folks. I’d consider us one of the more sophisticated hedgers in terms of E&P companies. So we’re hedging basis in all commodities, and even NGLs. So on the Permian side we’re 100% locked in in terms of the Midland, the Cushing differential at roughly $1 behind WCI. And then on the gas side where most of our gas contracts are linked to Waha price index, we’re 100% locked in for 2018 and then about 50% for 2019. So you can expect us to leg into those two basis differentials as well.

The other thing that we’re working on, too, is restructuring our contracts such that we’re not necessarily fixed to Waha and Mid-Cush. And we’re making progress on that front as well.

Scott Hanold: Okay. I appreciate it. Thanks.

Operator: Brian Corales; Johnson Rice.

Brian Corales: Nice quarter. I had just a question based on what Scott just asked. It sounds like — do you expect to have more capital going to the Permian either second half of the year or 2019? Is that the thought process now, or —?

Russell Parker: So right now I’d still anticipate that we’re going to be in the neighborhood of that 53%, 27%, kind of 20% split between Eagle Ford, Permian and Altamont for the year. However, as some of these new projects that we’re trying in the Permian materialize, it’s possible that we would shift that back. The nice thing is even operationally it’s pretty easy to move rigs and frac crews between the two properties. They’re only four hours away by car. Parts of the Delaware Basin are actually further away.

So I absolutely could anticipate a shift of CapEx back either late this year or into ‘19. But the key is, remember we’re running the company as if it’s all one asset. So we’re trying to do the things to maximize the value project by project and letting all the projects sort and then executing upon them, Brian, as it makes operational sense. So in a sense we’re basin agnostic because we’re just letting all the projects sort against one another. And we’re trying to do everything we can in each one of our three basins to unlock as much value as possible. I thoroughly anticipate that we’ll shift the CapEx spread as we go through our quarters and go through the years.

But to answer your question at a high level, yes, absolutely. I mean, that would be the anticipation. As you see how these projects do, you build a new development plan based on that and then you start shifting the capital back.

Brian Corales: That was helpful. Thanks. And then, obviously you have a good asset base, scalable inventory and high debt levels. How do you envision over the next, call it, 3 to 5 years — do you grow into your balance sheet?  Can you maybe just expand on that, on maybe reducing some of the debt levels?

Russell Parker: That’s a great question. And so first and foremost, we’ve got — we’re doing some great things to improve our cost structure in terms of just F&D and LOE, G&A per BOE, which is great. But ultimately, to get the debt-to-equity ratio where we’d like to see it and to get to free cash flow neutral and even positive at a lower prevailing oil price than $70 — $70 is great but you don’t want to build your strategy around oil price — ultimately what we’re going to have to do is some additional accretive A&D.

And so that means that we’ve got to take a hard look at our portfolio. We’ve got 4,500 wells to drill and we’re drilling them at a slow clip, if you will, based on what we can afford in our cash structure today. So as we go through time, we’re going to have to look at what deals are accretive and what makes sense, both from — not only from a divestiture standpoint, but also an acquisition standpoint in order to help us move value forward by taking our operational engine and applying it to even better rock and then taking the rock or the acreage that we just don’t have the capital to grow in the near term because of our current debt structure and rationalize that in order to help us pay down debt.

So it’s certainly going to be — the operational improvements, the cost control improvements. But ultimately long term you’ve got to have some accretive A&D to really get the balance sheet where we’d like it to be, without trying to make a bet on oil price. Right? Now oil price can save the day, but you don’t want that to be your strategy.

Kyle McCuen: Maybe one thing I would add to that, Brian, is that a key part of the financial strategy is insuring we’ve got adequate flexibility. So we’ve done a lot of work over the last 12 months to push out debt maturities, near-term debt maturities. And we’re addressing the RBL now. So we’re very comfortable with our liquidity position and the runway such that we don’t feel like it is something that we have to rush to in order to get one of these transactions done. We’ll continue to be judicious and make sure we execute the most value-accretive transactions as possible.

Russell Parker: And the key is, as you mentioned, we do think there’s a lot of value and some unlocked potential in these assets. So we’re doing the best we can, which is also to understand that as quickly as we can, which is, again, part of the reason why our CapEx was front-end loaded for the year 2018.

Brian Corales: Right. That was very helpful. Thanks.

Operator: Joe Allman; Baird.

Joe Allman: Russell, so I heard everything you said in terms of the various projects. Are there any that are particularly noteworthy in terms of not just cost savings but more outperformance that you can speak about?

Russell Parker: So we’ve certainly been — the wells we’ve brought on in the Permian have just now started to flow back, honestly, our first-quarter completions. And as a technical staff and technical team, we’re a little bit more conservative than most maybe. We like to really — we don’t publish 24-hour IPs. We like to really wait for IP 60s and 90s to really call performance. So that’s still a little bit early.

Certainly the re-completion performance and the drilling performance of our Altamont asset has been on par with what it was, so that’s been nice. And, again, those re-completes are some of our highest rate of return projects.

And in terms of the Eagle Ford, which we’ve been developing, we’ve put more capital into obviously in the first six months under new leadership. The exciting thing to see there is we are — one, we’re seeing a little bit more improvement in that volatile oil window versus prior company expectations, now that the walls have been on for a little while. And we’re certainly seeing a little bit more improvement in our parent/child relationships than maybe what would have been expected, especially as we utilize the new FMI technology and selectively complete our wells.

Again, it’s a little early on that, so we’re not advising as to type curve shifts or things of that nature. But obviously that’s the goal and I anticipate that to come down the road. And to that point, too, I want to make sure that everybody understands, our goal is to deploy capital as most efficiently as possible. So to that end, we’re worried about maximizing the recovery of oil and gas on the lease and spending the least amount of money.

So we really don’t even — when people get into the question of type curves I really try to shy away from that a little bit and focus more on really what was the historical F&D and where are you taking that F&D to. Are you dropping it by $1 or $2 or $3? Because ultimately in these examples if you can come up with a new technique and, for instance, drill one well where you used to drill three, but you actually recover the same amount of reserves for a lot less CapEx, then that’s much better. The challenging part I understand for everybody on the other side of the call, that can be difficult to model. Right? Because you need type curves and whatnot.

But certainly in terms of performance, with the early performance we’ve seen there, is encouraging. Not advising really on a change in curves or anything like that. But I will reiterate again we’re keeping our oil and production guidance the same for the year even though we had the unplanned event, which is the impact of the sliding-scale royalty in the Permian. So that gives you a little bit of an indication of where our head is right now.

Joe Allman: That’s helpful. In terms of making decisions about the portfolio and where you’re going to go going forward, is it too early to talk about that or no? Have you actually made some decisions about what do you expect the portfolio to look like a year or so from now?

Russell Parker: It’s too early to talk about that. We really haven’t made those decisions. Unless you’ve got a big checkbook, Joe, and you want to come talk to me later. But, no, we haven’t made those decisions just yet.

Joe Allman: Got you.

Russell Parker: And really, the key is you’ve got to unlock the value and then figure out what makes the most sense and what deals are the most accretive. The good news is, as Kyle pointed out, we’ve done a lot of great things as a company to extend our runway. So there’s no pending or immediate pressure that something has to happen right away, which I think is better for us and the shareholders. It allows us to ultimately unlock more value.

Joe Allman: That’s helpful. And then on the takeaway issue from the Permian, over the next year or so if you were to get interrupted in terms of your flow, what would be the cause of that?

Russell Parker: Kyle, do you want to take that one?

Kyle McCuen: Yes. I think I’d probably address it by what our current setup is today with the third parties we work with. So on the oil side — we’ve got a slide in the deck I’m sure you’ve seen — 90%, high percentage of our oil is gathered by another midstream company that has major connects to major pipeline takeaways at the major hubs.

And so we’ve got excellent connectivity there. And if you look at the map where our Midland Basin position is, we’re on the southeast position of the Midland and so we’re kind of at the front of the bus, if you will. And so more of the risk I think of folks getting shut in is on the back side of that.

And then on the gas side, where I think most of the questions are coming from in terms of permanent takeaway, there’s actually an abundant amount of capacity where we’re at. We’ve got multiple contracts with folks to process and treat our gas. And so I think from that standpoint as well we’re very well set up.

And that’s not to say we’re going to just not try to be proactive about managing the takeaway risk or even price risk. As I mentioned, on the financial side we’ve locked in a good amount of our gas price risk in 2018 and about half in 2019, and then 100% on oil in 2018.

And so the second part of that is, as I mentioned earlier, we are actively looking to I guess restructure our sales contracts to price off of, say, Magellan East Houston, or an LLS. And we’ve done some creative things just recently in Eagle Ford around that, where our marketing team has contracted the sale of our crude off of a Brent contract. So I think there’s a fair amount of sophistication there that our marketing team provides which provides a lot of down price support, but also creative ways to ensure we get the best price for our oil and gas.

Russell Parker: To tack on to what Kyle said there, too, Joe, a couple of other things to remember. The furthest we have to truck oil in the Permian is about 10 miles. So we don’t really suffer the logistical concerns that I think some of the other folks in the basin do. And our gravity is lower. We’re pretty much all 45 degrees and below, which helps, because when you really dive into bottlenecks you see that there’s not only a physical limitation, but that then leads to a gravity limitation and a trucking limitation. So those are a couple of key points to remember, is that we have the lower-gravity crude and we don’t have the trucking logistical issues because of our position and our position to the takeaway points that many other folks in the basin experience.

Joe Allman: That’s really helpful. And, Kyle, any other color on the RBL besides what you said in the release and in your slides?

Kyle McCuen: Sure. I mean, the RBL process is going well. I would say we’re on the final stages of discussions with the banks. Our goal, as always, has been to maximize the tenor, get something meaningful, and ensure we’ve got adequate flexibility with the terms of the amendment and maximize our commitment.

And regardless of the commitment size, we feel very good about our liquidity position. And that’s a direct result of the quality of our oil and gas reserves, the capital efficiency improvements that Russell listed off. You can see the lower cost that we’re delivering quarter over quarter. And that plus capacity on our RBL and ability to issue secured debt for liquidity purposes I think sets us up very well liquidity-wise.

So we’re in the final stages, as I mentioned. And my goal is to get that wrapped up as soon as possible and we’ll update the market here in the second quarter.

Joe Allman: That’s great. Thanks, everybody.

Operator: Phillips Johnston; Capital One.

Phillips Johnston: My first question is on the Eagle Ford oil mix. You saw a nice uptick to 67% in the first quarter, which I think is the highest it’s been since mid-’15 or so. Is that mainly a function of concentrating your recent completions more towards the northern portion of your acreage? Or did the recent acquisition that closed in the first quarter come into play there?

Russell Parker: So we haven’t completed any wells on the acquisition yet, other than we picked up some interest in some wells we were completing in the volatile oil window. We’ll be completing the first wells that are truly on a 100% acreage with the Carrizo acquisition later this year. But you are right; we did have quite a bit of completion activity focused in what’s called the

Ritchie Farms in the [Leman] area, which is a little bit oilier part of the acreage. That’s been more heavily drilled by the company. One of the things we’re doing — I didn’t mention this earlier, but — that also helped kind of mitigate the parent/child interference and also set up for the longer term, Phillips, for huff ‘n puff, is we’re trying to, if you will, kind of finish out leases one at a time, if we can. And so a lot of the activity was concentrated there.

Now that being said, just the Eagle Ford average oil production in general is higher than what our average had been as a company for awhile.

Phillips Johnston: Okay. And then do you think that 67% mix will sort of be relatively flat for the rest of the year? Or how should that trend?

Russell Parker: I’d like to see it go up as much as it can because of course oil is what really drives our EBITDA and nat gas does not. So we do focus on daily oil and we will continue to focus on daily oil. And we actually — that’s part of the reason why we guide to that first. And so but I think for the year we’re obviously keeping our guidance right about where it was in terms of oil mix and BOE. But absolutely, as we’re trying to optimize rate of return and trying to optimize F&D, that’s a driver and that’s a focus and it will sway the investment decisions going forward.

Phillips Johnston: Okay. And just to follow up on Brian’s question about chipping away at the leverage ratio, you guys have clearly pivoted more towards the Eagle Ford and away from the Permian at least in the near term, which I think is the right strategy. But is there any reason you guys wouldn’t try to sell a large chunk of your Midland Basin undeveloped acreage, which would obviously bring a lot of cash in the door without sacrificing much in the way of cash flow and production?

Russell Parker: You know, we’ve got to look at every deal and make sure that it is accretive. We’re not actively marketing anything today. And to your statement in terms of reasons why you wouldn’t do it, if you still had a belief that maybe there’s some things to unlock — and really this doesn’t apply just to Midland Basin, but to any of our acreage — some things to unlock in the basin or on your property that you might want to try to execute  upon that first if you have the appropriate liquidity runway, which we do.

But that being said, we’re not actively marketing anything, but obviously we do have quite a bit of inventory in the Company and ultimately if you get the leverage ratios where we need them to be, there will be a combination of not just looking at monetizing inventory that is very long life that we’re not going to get to, but also what do we possibly bring in the door that can be accretive from an EBITDA generation standpoint.

Phillips Johnston: Yes. Okay, thank you, Russell.

Operator: Sean Sneeden; Guggenheim.

Sean Sneeden: Maybe just as a kind of follow-up to the leverage discussion, Russell, I think you mentioned trying to improve the debt-to-equity ratio. Perhaps one of the issues there is the limited float on the equity. Do you envision the A&D efforts eventually being a mechanism to

improve liquidity in the stock while also serving to deleverage the balance sheet? Or how are you guys kind of thinking about that?

Russell Parker: Certainly longer term that could be an option. Now I can’t speak for the sponsors or the owners directly, but in terms of increasing the float at current price — or let me say it this way: The lower the price is the less there is the desire to do that. Right? That’s probably obvious to everyone. So I don’t think — I wouldn’t advise that that’s probably a near-term option, but possibly a longer-term option, yes.

Kyle McCuen: Sean, this is Kyle. I think in terms of the metrics that in addition to debt to equity, but more near term is debt to EBITDAX. And certainly in my view we’re on an improvement trend where we see EBITDAX in the first quarter and where we see it at current prices for the rest of the year. But I think with the capital efficiency improvements, the lower costs that we are realizing — you can see some of the dramatic changes on the LOE, G&A side — that we are in a — that is a trend that’s going to step us down on the leverage ratio over time, just organically. Now I think to accelerate it and ultimately get to our desired level debt to EBITDAX I think it will require some creative acquisition and divestitures. But that in itself is not the limiter to our overall financial improvement.

Sean Sneeden: Okay. Then I think that’s helpful. I guess just to be clear, do you have a thought process in terms of what the ultimate target in terms of leverage ratio that you’re shooting for?

(Technical difficulty)

Kyle McCuen: Sean, I think on the —

Russell Parker: (Inaudible).

Kyle McCuen: Yes. So longer term, Sean, I think we’re somewhere in the 3x. 3x or lower is where we want to be. Obviously we’ve got a lot of — I think Russell said “a lot of wood to chop.” Just within the past, I’d say, six months if you take our annualized first-quarter EBITDAX we’re at a 5.5x from, I’d say, 6s six months ago, looking again at the annualized basis. So we’re definitely on the right trend. And as we make further headway into improving the amount of rate and production we can generate with capital spend and do so at a lower cost, it further accelerates our path towards that target ratio.

Sean Sneeden: Okay. That makes sense. And then just on the guidance there, Russell, I think you gave some comments around impact on a sliding scale. It looks like the trend is still overall pretty positive there. Can you just talk a little bit about how you’re thinking about the exit rate or exit-to-exit type of growth, especially in lien of CapEx kind of stepping down in the second half? Any sort of color around that would be helpful.

Russell Parker: Well, sure. So of course a lot of the rate build comes after the CapEx is spent, so they lag each other just a little bit. Right? And you could back into it if you take Q1 actuals and the Q2 guidance with the year-end guidance. Then everyone could start to kind of back in to where they think it would be. Where do I expect us to be? Certainly December over January,

quite a bit higher and certainly Q4 over Q4 I expect that to be higher, certainly principally focused on oil because, again, oil drives the EBITDA.

Now, we are actively and dynamically looking at how we can improve our investments and improve the productivity of our wells as we go about them right now. So for now we’ve decided to, if you will, keep guidance flat, even with the impact of the sliding-scale royalties. So in effect we are guiding the year up, if you will. And then as we get further on in the year, we’ll continue to provide more and more clarity.

But my anticipation is that, yes, December over January you would see an increase and quarter over quarter you’d see an increase, assuming you have the exact same mix of properties, of course. But, yes, assuming that, then yes.

Sean Sneeden: Okay. That’s helpful. And then just, Kyle — sorry — on the RBL I just wanted to clarify one thing. On the extension that you’re in, is the anticipation that you’re going to still have the banks, or commercial banks, as an RBL lender versus some of the other alternative financings that have been out there on the market? Or how are you thinking about that?

Kyle McCuen: Yes, the intention is to keep the current construct of the RBL in the extension. So to get to your question directly, our intent is not to do something like a Sanchez first lien bond takeout, if that’s behind the question. We think we’ve got a good group of banks that are very supportive of the Company. They are very supportive and excited about the rate of change that they see just in this short period of time. And they are going to be willing to underwrite the commitments for a good number of years for the tenor extension.

So, like I said, we’re in the final stages of that process. And we hope to complete it sometime over the next — I’d say the next few weeks, but definitely within the quarter.

Sean Sneeden: Okay, perfect. I appreciate that. Thanks.

Operator: Joshua Gale; Nomura Securities.

Joshua Gale: Just had a couple just related to your annual guidance. I know that you noted in the press release that it’s as previously provided but subject to review. Just wanted to know the way that a couple of the data points or changes since the last quarter would affect the annual budget. First, the total amount of capital that you have earmarked for the drillco now that it’s being redirected to the Eagle Ford, relative to the initial budget just wanted to know if that would change the CapEx dollars net to you at all.

And then, second, this is a much smaller item, but the field gas that you’re using for the frac fleet, I’m just curious if that is still reported in the production volume but not included in the sales revenue from gas. And if it was in there, the original budget, and whether it’s still in there now.

Russell Parker: So on the natural gas used for the frac fleet, it’s a very small amount. It’s about 3 million cubic feet a day on average. So net to us you probably won’t even see it. We didn’t adjust the plans for that because it’s so small. So that’s that question.

And then in terms of things that would change the investment decisions and/or in terms of total net CapEx, obviously we were already working on drillco options when we set guidance, so we had anticipation that we would have some sort of drillco in some portion of the portfolio when the plans were made early on even. So our total CapEx spend anticipation is still the same. It’s still between 600 and 650, so midpoint call it 625. That includes, though, the $60 million roughly of new projects, the bulk of which that money’s going to be spent in the first two quarters of the year.

And then in terms of does it sway the amount of money we would potentially spend in each basin, we will be, at the end of the day, probably able to instead of maintaining one to two rigs all year in the Eagle Ford it will be two gross rigs, but we’re anticipating it will still be a similar amount of net CapEx spend with a drillco.

Joshua Gale: Great.

Russell Parker:  With a drillco.

Joshua Gale: Okay. Just one follow-up for you. The savings associated with the logging tools that you’re using, there was — I don’t know if it was referencing you specifically, but there was a service company that noted a case study in their 1Q release and referenced about $300,000 of cost savings. And just wanted to know if that — I’m sorry if you said it earlier, but is that, like, roughly accurate? And if you could update us in the Eagle Ford on where you were before in your AFE and where you are now, and understanding that the savings likely just apply to the infills.

Russell Parker: So that’s a great question. I don’t know if they were referring to us necessarily. But using that technology actually increases the cost of drilling the well, but it drops the cost of completing the well. And so on the first couple of pads where we’ve utilized it for an entire pad, on average we’re seeing about a net-net savings of a couple hundred grand per well. So, a little bit more than $200,000 per well, including the increased costs of actually running the log and then it does slow you down a little bit. You have to drill a little bit slower in the lateral to do it. But then you ultimately save money by not completing certain portions of the lateral. So that’s where we’re at right now. It’s a little bit over $200,000 like to like.

Now it could be more or less. Really that’s going to depend upon the other changes that you might want to make to your completion design specific to that well, specific to that location. So there could be some places where it could be larger, sure, some places where it might be smaller.

Joshua Gale: All right. Great color. Thank you.

Operator: Gail Nicholson; KLR Group.

Gail Nicholson: Just in regards to that natural gas frac fleet. You have one. Is there a potential, are you able, to get another one of those fleets, since it looks like that provided you good efficiency gains and cost savings?

Russell Parker: So we’re going to utilize that fleet in both the Permian and the Eagle Ford. There are not that many that are currently running in the country. So we’re certainly happy to be partnered with our vendor there, US Well Service. And, honestly, I do think that there’s a lot of future potential for this just in the industry. Honestly it makes sense to use your — one, it’s an inexpensive fuel. It’s on location. It saves quite a bit of trucking cost. It actually improves your safety because you have less equipment, less trucks moving back and forth on location. And in addition, anytime you can replace rotating parts such as diesel motor with an electric motor, it does become less of a maintenance problem. And so you end up with more efficiencies, better run time. So it can be a win/win for everyone.

Now, it does take some logistics. Just like the huff ‘n puff, it becomes much more important to handle all of your logistics. You’ve got to make sure you have sand delivery on time, water deliveries, so on and so forth, to really make it financially valuable to the Company. But we’ve certainly been pleased with it thus far and, like I said, we’re going to deploy it in the Eagle Ford. And ultimately if we could find a solution for that and do that in the Altamont as well, we’d love to. So it’s a great technology.

Gail Nicholson: In the presentation you guys mentioned that you’re testing new zones in the Permian in the second quarter. What zones are you going after? And then are your hopes that those would be an oilier composition mix than your existing Wolfcamp execution?

Russell Parker: So really everything all comes down to rate of return. Now, no matter what you do almost now because oil is running to $70 and natural gas is where it is — now depends on the price at the wellhead, right? Just because WTI is $70, not everyone is receiving $70 at the wellhead. But ultimately it’s not so much product mix as it is ultimate rate of return.

We’re testing right now some additional [bitumen] in the Wolfcamp that have been very lightly drilled in the basin by not only us but our offset operators. And then in addition we’re testing some zones above the Wolfcamp and some zones below the Wolfcamp. And we’ll do that this quarter. And those have been obviously a lot less developed in the region as well — somewhat developed but less developed.

And ultimately what we’ll be looking at is rate of return. So for instance, the zones above the Wolfcamp, our anticipation is that we may be looking at a similar reserve profile per well for instance, but with a significantly lower cost structure. And so that’s why you would develop it first. But ultimately, absolutely, oil mix plays into the game. But it really all comes down to just rate of return. How much money did we spend and how much money did we make?

Gail Nicholson: Great. And then just looking at — I know there’s an option for additional tranche in the drillco. Have you had any discussions with your partner in regards to that? And then is there any plans to potentially use the drillco shipping to the Eagle Ford and maybe test some incremental zones in the Eagle Ford in ‘18?

Russell Parker: So we don’t have plans for testing incremental (inaudible) or different zones up or down the hole in the Eagle Ford or in the South Texas Basin. At this point all the development

is really around that and then the new thing there is focusing on huff ‘n puff and the implication of value that that could bring. So no anticipation there.

And in terms of the drillco for us and our drillco partner, we felt like the best choice right now was to place this particular part of the partnership or this tranche in the Eagle Ford. The door is certainly not closed on doing more of them and doing more of them in other basins. This is what makes the most sense for everybody involved right now.

Gail Nicholson: Great. And just one last one in regards to realized pricing. You guys have done a really — I mean, your realized typical sale price of oil has improved. I know LLS has helped but I think also just in general ultimate pricing is better than historically has been. When you look at kind of your price elevations by basin, where are they today? Where do you think currently when you look through the remainder of ‘18 they could be? And then kind of from the standpoint of cost, when you move through ‘18 what’s that low-hanging fruit? The water handling should bring LOE down, but what other things do you think that you could just overall improve margins, which I think you have done a really good job over the last several quarters doing?

Kyle McCuen: Gail, this is Kyle. Yes, again, our marketing team does a really good job of making sure, one, our oil and gas and NGLs get delivered and sold through the markets, but also on the contract price as well. So in the Altamont, for example, we’ve got I think in the quarter it’s roughly 93% of WTI. And we’ve been able to be creative around how we structure contracts in that basin with purchasers such that we feel pretty good about that, holding that number for the rest of the year.

In the Eagle Ford where it’s almost basically at WTI we’ve definitely benefited from the LLS basis having a healthy margin over WTI. And our view is that — well, if you look at the market today that’s actually even higher. So I expect that to hold as well.

And in the Permian there’s some pressure obviously in Mid-Cush. But the thing to remember on that is we’re 100% locked in at a basis that is very much more narrow than where it trades today. So there really isn’t — what we realized in the first quarter net of hedging is something we expect to hold for the remainder of the year as well.

And the other thing to note is when you compare us versus peers, we really don’t hold firm transportation on the marketing side and that’s a differentiator versus some of our other operators such that some of the transportation, the cost to get it to market is already baked into the sales price. And that’s certainly the case in Altamont. So that just goes to further show how much better we are than other E&P operators in terms of realized price.

And on the cost side, I would say it was a good quarter. You can see on specific metrics, for example on G&A, we are on the low end of our guidance range at 230-ish. So we expect that to hold for the remainder of the year. LOE was slightly above the midpoint. And I think that will come to the midpoint, even lower, as our equivalent rate grows. And you can see that growth in the second quarter. Transportation we’ll get a little bit, go closer to the midpoint for the remainder of the year as we have some MVC contracts roll off. And then on production taxes,

being outside the range is really a function of higher oil prices, which is obviously a good problem to have.

So I think all in all a good quarter on the cost front and we think that’s going to further improve as we go through the rest of 2018.

Gail Nicholson:  Thank you.

Russell Parker: Now, Gail, to your question, though, there are other initiatives that are underway right now. So for instance, we’ve got quite a bit of CapEx, about $10 million to $12 million, that will be spending on saltwater disposal infrastructure in the Eagle Ford. We won’t realize those LOE savings until later this year and then on into 2019. But ultimately we think that’s going to end up dropping about, in aggregate, on the order of 90,000 loads of water on our lease roads and on our farm-to-market roads and highways in and around our Eagle Ford position and will have a significant impact on our LOE there. Saltwater disposal is one of the two largest line items in both the Permian and in the Eagle Ford.

Now we have also put that saltwater recycling facility in the Permian. It’s going to save us we think about $0.35 to $0.39 a barrel on water sourcing, but also probably on the order of about $1 million a year of LOE that hasn’t really shown up yet.

And then the other thing big initiative, both in the Eagle Ford and in the Altamont, we’re really heavily focusing, got a great collaborative effort between all of our field professionals and our engineers — matter of fact, our engineers, we have a couple of engineers that live in the field now, assisting with the (inaudible) maintenance and repair. Maintenance and repair is one of our bigger line items. That comes from two things. It comes from well failures and it also comes from really facility and road upkeep. So everything we can do to move fluids on pipe and to utilize natural gas as a fuel will help drop that. And we haven’t seen those savings just yet, but we anticipate that we will.

And then of course everything that we can do to extend the run time and the run life of our wells will also continue to share some further LOE reductions. So I want to compliment our operating team on getting that done and the improvements they’ve made.

But to your question, yes, Gail, there are some projects and some more initiatives underway.

And I’ll reiterate Kyle’s point. The other key thing is not only is it important to have a good cost structure and to get the oil and gas out of the ground, but you’ve got to sell it for a good price. And our marketing team certainly does that and does that well. Maybe it helps that the person leading it actually has the last name of Price. I don’t know if that’s all of it. But you’ve got to think about everything from what you sell, your actual individual NGL products to your differential spreads. It’s the whole picture, not even just hedging against WCI.

So that’s why I think a lot of the moves that we’ve made, for instance indexing some of Eagle Ford to Brent, a lot of it the rest of it to LLS, working the Mid-Cush spread, really beneficial in terms of yielding a good realized price.

Gail Nicholson: No, absolutely, margins are important. And you guys are inching out everything you can out of those margins. It’s great to see that.

Russell Parker: Thank you, Gail

Operator: Ladies and gentlemen, that will conclude our question-and-answer session. I would like to hand the conference back to management for any closing remarks.

Russell Parker: Thank you very much. Well, I appreciate everyone’s questions today, the interest in the Company, certainly, and your continued support. We’re very appreciative of that. We’re also very appreciative of our entire employee base and the great work and great initiatives that they are undertaking that are realizing some real gains, some real positive gains, for the Company.

So as I mentioned before, it is a very, very exciting time to be a part of the Company. And we are very, very optimistic about the quarters to come.

So thank you for your participation today and we will be talking to you again soon.

Operator: Thank you, sir. Ladies and gentlemen, the conference has concluded. Thank you for attending today’s presentation. At this time you may disconnect your line.