Earthstone Energy, Inc.
Q2 2017 Earnings Call Transcript

Published: 10 Aug 2017

[Operator:]

Good morning. And welcome to the Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions]. As a reminder, this conference call is being recorded. Joining us today from Earthstone are Frank Lodzinski, President and CEO; Robert Anderson, Executive Vice President of Corporate Development and Engineering; Tony Oviedo, Executive Vice President Accounting and Administration; and Scott Thelander, Director of Finance. Mr. Thelander you may begin.

[Scott Thelander:]

Hi, thank you. And welcome to our conference call. Before we get started, I need to disclose that the conference call today will contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and section 21E of the Securities Exchange Act of 1934 as amended. For a complete description of this disclaimer, please refer to our press release that was issued in connection with our second quarter earnings release 8-K on August 9. For a more detailed information about our Company, listeners are encouraged to read our quarterly report on Form 10-Q for the quarter ended June 30, 2017 in its entirety, our earnings release posted to our website, as well as all other reports and documents filed with the SEC. Our earnings release includes certain non-GAAP financial measures. Reconciliation of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained our earnings release. The content of today's call will include remarks from Frank regarding integration and development of our recently closed business combination with Bold Energy; remarks from Tony regarding financial performance for the second quarter of 2017 and remarks from Robert regarding operational and A&D matters. I am here to assist with Q&A as needed. I will now turn the call over to Frank.

[Frank Lodzinski:]

Okay. Thank, Scott. Good morning to all. First, I'd like to talk about how the integration efforts have gone with our business combination with Bold that we closed on May 9th. Thankfully we were successful in retaining a very capable group of former Bold employees with a clear focus on geology, land, operations and we continue to be pleased with their contributions to the combined company and we are looking forward to growing that office. Aside from realizing the benefit of these capable employees with a detailed knowledge of the assets, we believe our Midland presence is important and we will benefit as I mentioned by growing that office, as we expand drilling and completion operations and complete additional acquisitions. Overall the operations have gone smoothly as we continue to run one rig in the Midland Basin and we’ll start completing wells later this month. The results we are seeing have been very encouraging and we look to accelerate that drilling program and bring on a second rig likely early next year depending on commodity prices. We're still running one rig in our Eagle Ford properties. We have 11 programs as we discussed in our operations press release last month. The 11 well programs are currently result in about 3.9 net wells, 5 wells have been drilled and we're now on our third well out of a 6 well pad and we'll release the Eagle Ford rig thereafter. On a combined pro forma basis, including full second quarter Bold production, we're at about 10,600 Boe a day. But as Robert will comment, we expect that to decline a bit in the third quarter until our completions efforts start to ramp up production early in the fourth quarter. Going forward, we continue to focus on our cost structure as we execute our development program and will actively pursue acquisition opportunities to further expand our operated acreage and production. And as we have shown in the past, we will also continue to focus on our balance sheet and liquidity, as we continue to work through this low price environment. I’ll now turn over the call to Tony to provide a brief summary of our operational and financial results for the second quarter.

[Tony Oviedo:]

Thanks, Frank. For the quarter ended June 30th 2017 including Bold from the May 9 forward our production averaged 709,32 barrels of oil equivalent per day, which represents a 68% increase compared to the first quarter of 2017, and 111% increase relative to the second quarter of 2016. Production consisted of 66% oil, 17% gas and 17% natural gas liquids. We reported total revenues of 25.8 million and adjusted EBITDAX of $15 million and we excluded approximately $3.8 million in transaction expenses related to the business combination with Bold Energy. We also reported a net loss of approximately $55 million due to a non-cash impairment expense of $66.6 million, which resulted from a significant decline in commodity prices since year end 2016. As you all know strip prices at June 30th 2017 declined to over $10 per barrel or 18% for oil and $0.54 per Mcf or 15% for gas, as compared to December 31, 2016. Capital expenditures for the six months ended June 30th 2017 totalled approximately $19.7 million. We continue to have a balance sheet with a clean capital structure and low leverage. We currently have approximately $17 million of cash on hand and $70 million of bank debt outstanding. Our borrowing base remains at $150 million and our liquidity currently stands at about $97 million. I'll now turn the call over to Robert.

[Robert Anderson:]

Thanks, Tony. Good morning, everyone. Just like to remind you we put out a comprehensive press release on July 18th with a fair amount of information surrounding our activity in the Midland Basin and the Eagle Ford that I would point you to. I will highlight some of those items today, but won't rehash all of it. As a reminder, we now have 27,000 net acres in the Midland Basin with 21,000 net acres being operated. We are maintaining our exit rate production guidance of 10,500 to 11,500 barrels of oil equivalent per day. At the same time, we've reduced our overall capital budget by $15 million to a total of $150 million of CapEx for the entire 2017 year. To reflect a little less activity in our non-operated positions including the Bakken and the joint development agreement we announced in the Eagle Ford, all slightly offset by an increase in capital that we spent in the Midland Basin, First off, within our operated Midland Basin acreage, Earthstone continues to operate a single rig in Reagan County Texas. And as Frank mentioned we'll maintain this rig throughout the year and we'll look to bring in a second rig after year end subject to prices. We are currently drilling on a 2 well-padded central Reagan County, where we have a 50% working interest. At present, there are four wells waiting on completion, including our three well TSRH 28S Unit and the previously drilled single well pad, the Bold WTG unit 4-232 #1H. We have 100% working interest in all four wells. Completions on the three well TSRH pad will begin this month. We've we brought 4 gross or 2.9 net horizontal Wolfcamp wells online during the second quarter. These wells averaged 8,069 feet of completed lateral length with approximately 49 stages and 2,269 pounds of proppant per foot utilizing our Gen IV completion. In Western Reagan County, we brought online our first two wells in the Sinclair area where we have a 92.5% working interest. One of those wells in the Wolfcamp Lower B, the other is in the Wolfcamp Upper B and these wells had an average peak 30 day initial production or IP rate of 918 Boe per day with 86% oil. In Central Reagan County, we've brought online the Texaco-Coates A Unit 3 #1 HM and Texaco-Coates A Unit 4 #1 HM both with a 50% working interest. These wells are completed in the Wolfcamp Upper B and are approximately 660 feet apart to test out our spacing between wells. The two had an average peak 30 day IP rate of 868 Boe per day with 87% oil and after 45 days of production the 660 foot pair of wells had cumulative production 10% greater than previously completed Wolfcamp Upper B wells on the same acreage block completed with the same design. The previously completed wells in this area were on much wider spacing and therefore we're confident that the 660 foot spacing pattern will continue to drive our development plans. Moving onto the Eagle Ford, during the second quarter we entered into a joint development agreement for approximately 1840 gross, 625 net acres in Southern Gonzales County Texas with a financial partner. This JDA reduced our interests in the Davis and Pilgrim units which have been drilled and also reduced our interest in a future unit planned for 2018. The financial partner is obligated to pay a higher share of the capital expenditures on six wells, one of which is scheduled for 2018 to earn 50% of our interest in these units, as well as the adjacent acreage. We drilled a two well pad in the Davis unit where we have a 16.7% retained working interest and three wells in our Pilgrim unit with an 18.9% retained working interest. The JDA reduced our 2017 Eagle Ford capital of exposure by approximately $7 million inclusive of wells and facilities. We are currently drilling on our six well Crosby pad as Frank mentioned with a 50% working interest in southern Gonzales County and we're now on the third well of the six. These 11 wells will contribute – will conclude our 2017 Eagle Ford drilling program and we will plan to begin our Eagle Ford completions in September on the Davis and Pilgrim units and then proceed on to the Crosby unit. Our non-operated Midland Basin activity is expected to have fewer wells drilled compared to the beginning of the year and thoughts we had then and therefore we reduced our capital budget for our non-operated acreage to $5 million. We continue to generate meaningful production and cash flow from our Bakken assets and in the second quarter produced over 1000 Boe per day from this asset group, which is our highest production level ever in the Bakken. We are going to evaluate a sale that could take place before year end. We are also in the process of divesting other non-core assets that have minimal PDP value and are low margin properties. We are focused however on additional growth opportunities in the Midlands Basin and have been reviewing several potential prospects that includes trades in order to block up acreage and extend laterals, bolt-on opportunities adjacent to our existing acreage, as well as larger acquisitions. As an example, in July we completed a trade in Upton County whereby we blocked up acreage such that we have approximately 2650 net acres and 52 locations in the Wolfcamp A, B Upper and B Lower with additional upside locations in the Spraberry and Wolfcamp C. Absent additional trades related to this acreage, we expect that our current average laterals will be approximately 6650 foot in length with an average 95% of working interest and an 80% net revenue interest. This acreage is 100% held by production and will allow us to not only control the pace of development but has increased our lateral lengths over the previous acreage configuration in this area. We will have a slide in our updated presentation that will be loaded to our website in the next day or two which will show the acreage lay out pre and post trade. We plan to benefit from additional trades in the coming months similar to this one. So I'll turn the call back to Frank now.

[Frank Lodzinski:]

Okay, Robert. Thank you. Just to comment a little bit on the trades. Our folks here in Houston are from a land and operations and geology standpoint have integrated very well I believe with the folks in Midland. I mentioned earlier that the Midland presence is important to us and this whole area of trading, acquiring bolt-on acreage and doing all the things to generate longer laterals and more locations is something that's going to be very important to us going forward. I hope that the market recognizes the fact that we transformed our company into a high growth Midland Basin operator. We're already seeing great results from our newer wells in the Midland Basin and are very pleased with how the integration of operations and staffing and so on as I've said have gone. Our goal is to further expand our acreage position with a focus on the Midland Basin and frankly we can't wait to close the next large deal. We appreciate the continued support of our banks and our equity investors. We’ll now open up the line for questions.

[Operator:]

Thank you. [Operator Instructions] Our first question comes from Neal Dingmann with SunTrust Robinson Humphrey. Please go ahead.

[Neal Dingmann:]

Morning, guys. Robert my – maybe first question is for you. There's been obviously a lot of activity now and by your sales [ph] with Bold and just a lot of offset operators in that new area in Reagan. Could you talk maybe about, I know you talked about kind of a single well, single rig program. A lot of optionality there, I mean you've already talked about just today Lower Wolfcamp B, Upper Wolfcamp B you know, are you able to lay out yet how are you going to tackle that here in the next several months, as far as what - you know, how you're going to target or is it still too early to know?

[Robert Anderson:]

For the next few months we have a plan that's pretty well set in terms of what we're targeting and it's generally the A or the Upper or Lower B depending on where we're at. But I think as 2018 unfolds you know, we're going to have more optionality of how we further develop local areas, whether we completely drill out a B Lower or a B Upper or an A or we stagger them or whatnot. And so we're going through some of that review and analysis right now.

[Neal Dingmann:]

Okay. And then question for you Frank, I don't know if you'll have the answer on, just kind of, I guess a bit surprised not by your comments, but just the non-op in the Midland Basin, giving the returns there, surprised your operating you know, partner would be slowing down. I mean, again I know that's not your call, but anything that either Robert you or Frank could add on why they would do this given the economics in such a good area?

[Frank Lodzinski:]

Well, I'm not going to speak for them. And we have good conversations going with folks and so forth. The fact of the matter is on a non-operative basis, we've got about you know, 6000 acres and that is a small fraction of what the operators on that 6000 acres have. So Robert you might check me if I'm saying anything wrong. Those operators have active programs going and we just haven't pushed to get anything going on a non-operated acreage right now, because we got plenty to do with Bold. Now as we further refine our plans you know, beyond what Robert just talked about, we’ll I have continued conversations with them and integrate that. But I don't think it's a function of anybody slowing down. I think it's a function of them being off doing - doing other things and us not pushing. Is that a fair statement do you think?

[Robert Anderson:]

Yeah, absolutely. We thought we would have a little more activity and maybe the Glasscock, Howard County areas that we're seeing because those operators have plenty of acreage in both of those places, as well as others. We are seeing some operators in Reagan County where we'll have in smaller interest in certain wells that will end up participating. So just kind of our non-op budget got moved probably to a different area and smaller interest and less activity than we thought that's all.

[Neal Dingmann:]

And then - I don't want to get ahead of myself, just Frank you know, Sameer [ph] was going to ask on M&A, does this dovetail into either talking about M&A, talking about further trades, you know, Frank or for you Robert, is that opportunity with that - you know, with your partner up there, you've got the non-op acreage with or is it just is – is there just as good opportunity elsewhere. I mean, I guess what I'm asking is, is there more opportunities there than anywhere else as far as potential trades or M&A activity Frank or is it just sort of every way you're looking?

[Frank Lodzinski:]

I'd say that we haven't focused solely on acquisition opportunities with in and around areas where we're a non-operator, okay. Of course, that's going to be an element of going forward to try to increase our operative position and do some trades, things along those lines. As you know and as our Houston folks and our Midland folks have been chasing and take a look at the one trade that we're going to have in our - one significant trade that we're going to have on our web page, you know, unlike the Eagle Ford and other places there seems to be activity in the Midland Basin where everybody wants to trade to get the longer laterals and do things like that. There's a level of cooperation out there that I'm frankly very, very pleased with, okay. So we're trying to set up the organization meal, so that you know, we've got the folks focusing in on bolt-ons, trades, extending laterals, staying ahead of the rigs and doing all that on a daily basis. The business development and all that bolt-on acreage trades and everything is an integral part of what we're doing and we've got good folks to do that. Robert and I and some of our team members here in Houston with the input from Midland are chasing bigger deals at the same time and we've got a hit list of people that we're talking to and have we've bagged one yet? No. Will we bag one within the next year or so or next six months or so? That's our goal every day. So I don't know how to talk about it any better.

[Neal Dingmann:]

That that's clarifying. Thank you, all.

[Operator:]

Thank you. Our next question comes from John White with ROTH Capital. Please proceed.

[John White:]

Good morning. Thanks for taking my call. I just wanted to double check that guidance is remaining unchanged at 10,500 to 11,500 Boe’s per day for an exit rate at 2017?

[Robert Anderson:]

Yes sir.

[Frank Lodzinski:]

That's correct, John.

[John White:]

Okay. Well, nice quarter. Congratulations on getting Bold done and thanks for clarifying that for me. Appreciate it.

[Frank Lodzinski:]

Okay. Thanks, John.

[Operator:]

Our next question comes from John Aschenbeck with Seaport Global Securities. Please proceed.

[John Aschenbeck:]

Hey. Good morning, guys. Thanks for taking my questions. Was hoping to get a little more color on how you're thinking about the addition of the second rig at the end of the year, I know it's obviously going to depend on prices, but I didn't know if there was a ballpark price you're looking for specifically. And then conversely you know, at what point if any would you potentially slow up on activity there?

[Frank Lodzinski:]

What was that second part, what price will we slow up on activity?

[John Aschenbeck:]

Yeah, I mean, that obviously the commodity environment - you know, a lot different than a few weeks ago, probably looks a lot better. But you know, I don't know if its sub-40 would you slow down the activity there, just how you're thinking about activity levels at various commodity prices?

[Frank Lodzinski:]

Well, I think - you know I think I'd be perceived like a lunatic if I didn't say that sub-40 we'd be considering slowing down and things like that. We're avoiding on our relationships with the drilling contractors and so forth are good. So we're avoiding long-term contracts at this point. You know, the question always becomes, well if the prices dip, just like they dip down at 42 you know, I mean how do you run a company, how do you schedule logistics, how do you schedule the infrastructure, how do you schedule the people and all of that. So the prices, you know, it's somewhat intuitive and somewhat subjective. Within the last month or so the prices dipped down to 42 and I thought I looked this morning and they are 50s. So you know, not to be smart alec, but you got to - you know, you got to tell me how long it's going to be 40. You know, if that's two weeks, that's one thing, if that's two months, that's another thing. So the good news is that that you know, I think we got economics clearly in down deep into the 40 range and it looks really good above 50, really good above 50, plus time will tell if the production keeps on going. But as Robert mentioned the results we're seeing are very good. What we anticipated and what we hoped for and I don't think it's a stretch to say that everything we're seeing is meeting or exceeding our type curves. So I don't know how to answer that. I mean if it's going to go some 40 for a while obviously we've got to slow down, if it's going to go over 50, then obviously we have to speed up and we're going to try to avoid long-term contracts, so we don't get dipped by volatility.

[John Aschenbeck:]

That is actually perfect. Appreciate that. That was great. And then kind of keeping with that same theme, if you did move forward with adding a rig at the turn of the year, at that point do you think you’d be able to lock down a dedicated frac crew. I'm just trying to understand if that would mitigate some of the potential risk around timing of completions?

[Frank Lodzinski:]

It’s kind of the same answer on a dedicated frac crew. We've had a good fortune historically with - essentially having a dedicated frac crew like we did in the Eagle Ford for quite some time without having a long-term contract. So I think you know, I think there's a good opportunity to have that and we're talking to the folks right now. We're going to start fracking wells you know, hell in a week or so, okay, and maybe soon. So we're going to try to avoid long-term contracts, but yes we’d want to have a dedicated frac group. Because once again our operational and field folks some of which are located in Midland and on the ground there, okay, they need some running room to plan, organize, get the crews all coordinated ,train each other and so forth. So we always strive for something like that.

[John Aschenbeck:]

All right. Appreciate it the color. That's it for me. Thanks, guys.

[Operator:]

Thank you. Our next question comes from Jason Wangler with Imperial Capital. Please proceed.

[Jason Wangler:]

Hey. Good morning, guys. I was curious as the well results you talked about Robert from the July release. You know they are looking and how since you got the acquisition going, you know really oily, maybe more so than I thought and I think even more so maybe than your type curve, as far as just the oil weighting. Could you maybe talk about what you're seeing there if the different frac is helping that or any you know, commentary you're seeing around that?

[Robert Anderson:]

Well Jason, as is typical in this basin and as you're probably reading some of your peers talking about, gas rate start out rather low and then they increase over time hopefully slowly and then they flatten out. And if you look at our type curves, we start out obviously with higher oil production rates and lower gas rates. And then over time we end up around 70-ish percent oil cuts without the NGL So just plain oil. And if you look at our corporate wide contribution from the Bold assets its 67% oil. So it all kind of blends from a long-term perspective of having about 65% to 70% cent oil cuts. But early on these wells start out with much higher oil cut.

[Jason Wangler:]

Okay. Okay, just wanted to see if there was anything different, just given the way the fracs are going. That makes sense. Like you said it's been - it's been a topic of late for sure. And maybe Robert as well, just as you look at whether it's the one rig or two rig program you know, in the next year whatever it is, how do you see - where are you going to be focused. I mean obviously you have a lot in Reagan, but you talked about that Upton County as well. Just how you see whether it's a one or two rig program, the development pace and where you kind of be focused as you look at 2018?

[Robert Anderson:]

If we were just subject to only running one rig most of our activity would be in Reagan County. We have only a little bit outside a Reagan County, one or two wells in Upton perhaps and a couple of wells up in Midland County. As we ramp up to a two rig program, we're going to spend more of our additional capital, at least I think we would spend more of it in Midland and Upton County and keep one rig busy in Reagan County, is kind of a view that we have going forward.

[Jason Wangler:]

Thank you for the help. Appreciate it…

[Robert Anderson:]

We have some obligation while still in Reagan County, so that's what's driving some of our decision of where we're going in 2018 with just one rig progress.

[Jason Wangler:]

Okay, great. Thank you.

[Operator:]

Next question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Morning, guys. I was hoping you could maybe touch on the cost side of things, as it relates to the Permian activity, obviously been seeing a lot of peers talking about some upward pressure. So can you guys just maybe give us kind of the latest and greatest on what you've been seeing on the cost side and maybe as it relates to kin of the [indiscernible] cost we see in your most recent Decker?

[Robert Anderson:]

Yeah, the drilling side has got levelled off I'll say, the completion side there still is some cost, upward cost movement. We're hoping that these stages we're going to do on this 3 well pad will end up $70,000 to $75,000 per stage. That's $10,000 more than the stages that were done in April or May. Half of that is a little bit change in the way we're doing things and half of it is pressure pumping increases. So you know, we're seeing - we're still seeing probably a 5% to 8% percent, maybe 10% increase in costs and then part of it is - a little bit of a design enhancement you might say.

[Jeff Grampp:]

Okay, perfect. And then just generally, I guess I go back to Jason's question on where you guys are focusing, but more so I guess on the pad size or spacing here you guys talked about the 660 foot wells actually outperforming even with a similar frac design, is that - is the 660 kind of the base plan going forward. Any plans to do anything different higher or lower? And then I guess, any interest in and sea bench [ph] wells in Reagan given what some peers are seeing there?

[Robert Anderson:]

So yes, our 660 plan is kind of how all our sticks are laid out. You might call it - if we do an Upper and Lower B you know, the spacing actually might be a little bit tighter. But given that there are two different targets that shouldn't be any issue whatsoever and we've seen some of that - we've already drilled some wells similar to that and that's not the issue. So our plan is laid out at 660. We're probably not going to develop you know, an entire unit at 660 in one bench in 2018 anyway, just given our obligation drilling that we're going to do. And as far as the sea goes [ph] we love the results that others are having. And you know, we're holding that sea card in our hip pocket for the time being and at some point in 2018 if we run two rigs, maybe we'll find an area where we do drill sea well.

[Frank Lodzinski:]

Hey Jeff take this - take what I say with a bit of humor intended or so on. But I was going to say exactly what Robert said you know, if we stick with one rig because of commodity prices and things like that, we'll probably stick to our knitting on the A and B. When we get to a second rig, okay, this is what a little bit of humor here. We are going to drill a sea well or two out there, just so I can tell you and some of your peers out there, see I told you so. So I was actually talking with some of your peers out there about that last night. So yeah, we want to prove to you that we've got upside in all that acreage.

[Jeff Grampp:]

We'll look forward to that, that two word [ph] pace and keep our fingers crossed. I appreciate the time guys.

[Frank Lodzinski:]

I appreciate it. Thank you.

[Operator:]

[Operator Instructions] Our next question comes from John White with ROTH Capital. Please proceed.

[John White:]

Hi. Thanks for letting me get back in line. Robert, I believe you've covered this at the inception of the call and I didn't have my pencil ready. But the number of gross and net wells you plan to bring online this year is the same as set forth in the July 19 press release?

[Robert Anderson:]

Yeah, we haven't changed that yet John. We should be able to drill all the wells. We may have you know, a little bit of - whether they come online or not. We may get all - we may not get all the wells fracked, but they'll be in process and so we should end up with about the same well count, I mean that's what our plan is at the moment, so.

[John White:]

Okay. And the one rig is going to be focused - is going to say in Reagan County?

[Robert Anderson:]

We may drill two wells in Midland County and we may spud one well in Upton County in our plan if it stays the way it is right now, still doing some juggling around at the moment, but that's the plan.

[John White:]

But it looks like your deals [ph] and wells are drilling pretty fast?

[Robert Anderson:]

They should be - our target is less than 15 days and so we have a bigger bull’s-eye out there and we haven't hit it right in the middle yet…

[John White:]

We got – here is the last one and this one, so set the target for the guys at 12 days and see if you think…

[Robert Anderson:]

We're getting there.

[John White:]

And lastly, this Reagan County focus will be Wolfcamp A and Wolfcamp Lower B?

[Robert Anderson:]

And in some cases Upper B. We've got both the Upper B and the Lower B in Reagan County.

[John White:]

All right. I think that take care of me. And thanks again.

[Operator:]

Thank you. There are no further questions. I would like to turn the floor back over to Frank for closing comments.

[Frank Lodzinski:]

Okay, thanks. We're out of here and we're going back to work. You know, where to reach us if you need us. So thank you very much for your attention, questions, calls and interest. Thank you.

[Operator:]

This concludes today's teleconference. You may disconnect your lines at this time. And thank you for your participation.