Rose Hill Acquisition Corporation
Q4 2018 Earnings Call Transcript

Published: 28 Mar 2019

[Operator:]

Good day, ladies and gentlemen, and welcome to the Rosehill Resources Q4 2018 Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference call is being recorded. At this time, I would like to turn the call over to your host, John Crain, Director of Investor Relations. Please go ahead.

[John Crain:]

Thank you, John. Good morning, everyone and welcome to today's conference call to review Rosehill Resources' fourth quarter 2018 operating and financial performance. After I cover the forward-looking statements, Craig Owen will review key items, operational updates and financial results. We will have a question-and-answer session and Craig will then close the call with some brief comments. Also joining us today on the call is Brian Ayers, our Vice President of Geology. Gary Hana, our Chairman and CEO is not with us today due to a family emergency. I would like to remind you that today's call includes forward-looking statements and certain non-GAAP financial measures. We believe our expectations are based on reasonable assumptions. However, a number of factors could cause results to differ materially from what we discuss. We encourage you to read our full disclosure on forward-looking statements and our SEC filings and the GAAP reconciliations included in yesterday's earnings release. With that, I will now turn the call over to Craig.

[Craig Owen:]

Thank you, John, and thank you to everyone for attending Rosehill's fourth quarter earnings call today. We know Gary would have liked to have been with us today and our thoughts and prayers go out to Gary, Su and their family during this difficult time Moving to our update and echoing Gary's comments in our press release filed last night. 2018 was a year of tremendous accomplishments for the company. We met all of the targets we set, and surpass the upper end of our guidance range in both production and adjusted EBITDAX. We have carried that moment into 2019 with an acreage expansion in our Southern Delaware position and a boost in liquidity by over a $100 million from our borrowing base redetermination in our announced asset sale. For the fourth quarter, our average net production was 22,779 barrels of oil equivalent per day, up 15% compared to the third quarter of 2018. For the year of 2018, our average net production was 18,337 BOEs per day more than 3x the amount for full-year 2017 and have exceeded the top end of our 2018 guidance range by 8%. Our fourth quarter production growth is driven by continued strong well results in our Northern Delaware area and also from bringing wells back online that were shut in from activity in the third quarter. We continued our progress on cost improvements during the fourth quarter, decreasing combined lease operating and cash G&A expense by $1.06 per BOE from the third quarter. Compared to the first quarter of 2018, we’ve reduced lease operating and cash G&A by $5.71 per BOE or 43%. These achievements are direct result of our infrastructure investments in 2018 that are now starting to pay off as we reach scale in our production. Earlier this month, we released our year reserves which grew significantly over 2017. Proven reserves increased 55% and PV-10 increased a 102% over last year. These results drove an increase in our borrowing base of $80 million to $300 million, almost 40% above the previous level. As I mentioned earlier, this increase along with our announced asset sale in Lea County, New Mexico provides meaningful improvement to our liquidity profile. The sale of our Lea County assets has a very small impact on our production reserves. It will have no impact to our 2019 guidance or borrowing base upon closing. Our recently announced farm-in agreement in Southern Delaware allows us to earn up to 2,200 net acres from drilling seven wells and providing a 25% carry. This acreage is contiguous to our existing high quality Southern Delaware footprint now at almost 10,000 acres allowing for extended laterals in scale from our present infrastructure. We've updated our Southern Delaware acreage map in our current investor presentation on our website to highlight how the farm-in acreage further blocks up our position. Turning to a broader update on Southern Delaware. We remain active on our development of the asset and now drilled 13 wells on this acreage. We expect to have results soon on six recently completed wells and we will share those when we have post flow back data. In our earnings release we provided additional information on these wells in our updated investor deck, we’ve identified all wells we've drilled in the Southern Delaware. As we’ve previously indicated, our current plan in the South is to install ESP's on wells soon after initial flow back. Earlier this month we provided results on an ESP installed in the Southern Delaware on a well drilled in the third quarter and we are encouraged with this data. In our Northern Delaware area, we brought on a three-well pad targeting the lower Wolfcamp A formation on our Z&T 32 lease along with our first 2nd Bone Spring Shale well and are highly encouraged with the initial production results and the potential of this interval. These wells -- these well results are summarized in our earnings release. Altogether, for the fourth quarter, we drilled 8 horizontal wells and completed 3, ending the quarter with 8 drilled uncompleted wells. Due to our completed well count in the quarter and forecasted activity pace, we expect our net production in 2019 to be weighted towards the back half of the year. As previously mentioned, our overall guidance plan for 2019 did not change as a result of the farm-in agreement, our increasing liquidity or announced asset sale, including our intent to keep our CapEx in line with expected EBITDAX or unlevered cash flow. Our well count and activity mix be dynamic and we remain positioned to be responsive to any significant changes in the commodity price environment. Now turning to financial results. Fourth quarter revenues were $83 million and production totaled 22,779 BOEs per day comprised of 73% crude oil, 14% NGLs and the balance natural gas. For the fourth quarter of 2018, Rosehill reported net income of $50.2 million or $2.35 per diluted share, which included a $199.4 million non-cash pre-tax gain on unsettled commodity derivative instruments. We generated adjusted EBITDA of $63.6 million for the fourth quarter, an increase of 12% compared to the third quarter of 2018. Our realized oil price for the fourth quarter averaged $48.51 per barrel of oil and a total equivalent realized price of $39.60 per BOE, both on an unhedged basis. Turning to cost, total cash operating expenses were $21.3 million or $10.17 per BOE, which consisted of $9.7 million in direct lease operating expense or $4.63 per BOE, $5.9 million in cash G&A expense or $2.83 per BOE, $1.7 million in gathering and transportation expense or $0.81 per BOE and $4 million in production taxes or $1.90 per BOE. On a unit basis, our cost improved consistently throughout the year as we realized economies of scale. Altogether, our fourth quarter cash operating expenses per BOE were down 37% compared to the first quarter of 2018. This is especially noteworthy considering the fourth quarter included initial production in our Southern Delaware area and required significant coordination of infrastructure to process our production and produce water. Total liquidity at December 31, 2018 was $46 million. This amount was increased by $100 million pro forma for the borrowing base redetermination in Lea County asset sale mentioned earlier, which is expected to close in early April to a pro forma level of liquidity of $146 million at December 31, 2018. We feel this level of liquidity is strong given our balanced capital plan in 2019 and we have several initiatives in progress, including the potential monetization of our Northern Delaware produced water system that could further improve our liquidity and leverage profile. Turning to hedging. During the fourth quarter we're pleased to have a strong hedge book in what quickly became a volatile oil price environment. We did not add any fixed price oil positions during this time, but we have recently added Midland/Cushing Basis Swaps for 2020 through 2022 at a premium over WTI, as well as the natural gas fixed-price and basis swaps for the summer of 2019. These new positions are further outlined in our press release. And lastly, I'd like to provide a brief update on our leadership transition. Earlier this month, we announced that David French will be joining Rosehill as President and Chief Executive Officer. We're excited to welcome David, and have a tremendous amount of confidence that his vast oil and gas leadership experience will be a great asset to Rosehill. We expect David to officially assume this role in a few weeks and we look forward to introducing him to our investors in the near future. And as we’ve previously indicated, Gary will remain Chairman of the Board and continue to be closely involved with the company to ensure a smooth leadership transition. And with that, , we’re ready to take questions.

[Operator:]

Thank you, sir. Our first question comes from Neal Dingmann from SunTrust. Please go ahead.

[Neal Dingmann:]

Morning all. Craig, my question is -- two questions here. One, you talked about the 6 wells coming on in the South. Could you just talk about overall activity between the two areas just sort for the remainder of this year and as you enter next year, how you sort of see the split between the two?

[Craig Owen:]

Yes. We are -- I think as we said, we will certainly be balanced in kind of be flexible and dynamic as we move through. Right now as we expect for the year, we are averaging certainly less than two rigs for the year. The majority of that activity to date has been rough balance between North and South and it will kind of ebb and flow between the two areas as we finish up the rest of the year, I say that early in the year. But it will be between both and certainly as we get into 2020, the South will become increasingly their part of our development plan in production profile, result profile, etcetera.

[Neal Dingmann:]

And then maybe currently looking at that just maybe on details on the cadence, if you’re looking particularly at the South, how you’re going to -- after the 6 wells come on, and if you could talk cadence or just how you would sort of go about attacking the remainder of the South, again for the remainder of this year going into next year how you are thinking about that with you or Brian or the guys?

[Craig Owen:]

That sounds good. Brian probably best answer that.

[Brian Ayers:]

Yes, Neal, we’ve got a rig running right now could in fact if you got the new slide deck up, Neal, Page 11 has a breakdown of what’s going on right now. We’ve got a rig running on our Silow well to the very south end of the block. We've got a handful of DUCs that will be fracking while we just finished fracking 6, we are going to send that frac crew back up north, and then we’re going to bring the frac crew back in about two months and frac the DUCs. After we finish the Silow, we are going to drill the first well on the farm-in in 10 and 12, and then that rig is going to go away for a short while. We will bring rig back and finish drilling long reach wells for the fourth quarter, that rig will come back around the beginning of October. I think to kind of address your first question on balancing kind of in a rough sense, we are working at kind of two thirds north and one third south for this year and for next year given the -- the drill schedule, in part imposed because of some lease clocks and because of our -- of our farm-in, we will probably be closer to half-and-half. But there's still little bit of thought process there, Neal.

[Neal Dingmann:]

Okay. And then, Brian, just last one, if I could, just on the south on these newer wells are going forward, will you -- maybe just talk about will you put everything on lift immediately or how do you sort of think about flowing these wells down south? What do you think ultimately are the best?

[Brian Ayers:]

Well, in fact we start to flow back. We have fracked 6 wells on the North side. We had a three-well pad on the East flank of our State Blanco track and we had our Trees Estate well as a DUC. That Trees well is actually the first well that we drilled last year. As we completed that as a four-well pad, one was a well in 3 Wolfcamp -- Wolf B wells. On the east flank of that Trees Estate's track, we actually have a two-well pad and it's a stack A & B pad. All 6 have been fracked. The first four have been flowing back for about a week. We are really excited about what we're seeing now, but the first of those wells is going to go on pump next week. Our plan is to have all four of those on pump within about 10 days. So going forward, we expect to flow back for a week or so, allow the wells to get kind of stable and then start lift .

[Neal Dingmann:]

Very good. Thank you all.

[Brian Ayers:]

Thanks, Neal.

[Brian Ayers:]

Thank you.

[Operator:]

Thank you. Our next question comes from Jeffrey Campbell from Tuohy Brothers. Please go ahead.

[Jeffrey Campbell:]

Good morning. The first thing I want to ask is just kind of a thought question. I was just wondering how you guys think about our view, David getting up to speed with what Rose is doing, considering that 2019 plans are already very well worked out and are already active and ongoing?

[Craig Owen:]

Yes, he has already hit the ground running. He is doing a lot of homework even before he gets in the door, obviously done a lot to the process with the Board and Gary. So he knows the company fairly well. Obviously, he has got to learn more, but he will get up speed running very well, running with the plan. As you said, he will be a member of the Board of Directors as well. So we kind of executing on the plan for this year, but strategically guiding the company as we move forward. So I think it will be fairly seamless, if not exactly seamless, he will get up to speed quickly, well, in addition to investors and so forth in due course. But that as well within the first, call it, two months or so max on that transition. But, Jeff, I don’t know if that fully answered your question, but we don't expect a hiccup at all, especially since Gary remains with the company and just elevating back up to chair and he will help with David's transition as well as the entire management team.

[Jeffrey Campbell:]

No, I think that was a great answer. I appreciate that. We see the potential for Pecos County acquisition opportunities increasing in 2019. I was just kind of wondering, we always talk about we are looking for increased acquisition. So I was just wondering about your appetite for a small bolt-on type acquisition versus a larger position that one should present itself during the year?

[Brian Ayers:]

Brian here. dear I would agree that we see that there will be some things happening this year. We will focus on what we think is the best rock. We certainly have the capacity this year going forward to do small things. We actually like the drill to earn route, which I think works well for us. But I don’t know -- I really can't address what the top end of our size range would be, but it's probably a real number, right? Craig, you want to there a bit?

[Craig Owen:]

Yes, I think -- there should be a lot of opportunity as Brian said, we think these farm-ins are driller earns kind of earning in our sweet spot with kind of what we can do within our balance capital plan. We are not looking to really change that. We said even with this farm-in we are not changing our capital plan. So we will stay disciplined, but look for those opportunities that can be managed within our structure. And now that we've increased liquidity significantly, we are certainly not using or looking to go the other way on that again. We like the liquidity where it is. So we will look throughout those opportunities, but they will be balanced, of course, with -- kind of the cost to play the game.

[Jeffrey Campbell:]

Okay. That’s helpful. Looking at Slide and thinking about the 2019 program, could you just -- I’m asking you to be as specific as you want to be, but can you identify the primary zones that are going to be produced in both Northern Delaware and Southern Delaware in 2019?

[Craig Owen:]

Yes. Up North, we are going to focus on drilling out the Wolfcamp A X/Y and A Shale zones. We commonly drill a 3rd Bone Spring well along there too because that's all one tank. We found that if we drill and complete the 3rd Bone Spring down through the Wolfcamp A Shale, we get the best wells. We will also be drilling the 2nd Bone Spring Sand. In the South, we are going to focus on the Wolfcamp A & B. I believe they probably have 1 Bone Spring well in the mix.

[Jeffrey Campbell:]

Okay. That was helpful. And my last question is, as you made it very clear, you’re going to align cash flows and spending in 2019. I was just wondering what percentage of your wells will be longer laterals, which were commonly told are more economics versus shorter laterals still make strong returns?

[Craig Owen:]

In the South, thanks to the farm-in. We are going to drill in 2019 3 Long Reach wells. Going forward, again in the South, if you refer to the chart on Page 9, you will notice that -- and this is post that deal, we've got a substantial tranche of Long Reach wells to do. In fact going forward, I would expect that on the order of 40% or so of our wells are going to be very Long Reach.

[Jeffrey Campbell:]

Okay, great. Thanks. That’s very helpful. Well, I will say hi to David for us. We look forward to seeing him soon.

[Craig Owen:]

Thanks a lot, Jeff.

[Operator:]

Thank you. Our next question comes from Jeff Grampp from Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Good morning, guys. Nice quarter. Was curious, Craig, on -- you guys made obviously a nice improvement on liquidity front here. Is that at all change your strategy or thought process regarding potential water monetization just in regards to the timeliness or anything strategically different, I guess, than how you guys maybe thinking about it a couple of months ago?

[Craig Owen:]

Yes, nothing strategically different as we mentioned in the comments. We are active in a number of initiatives including that one, that we are actively working. So nothing strategic or nothing changing in that strategic plans. We are still going on that path, seeing what we can get done and we are -- we are not new in where we’re in that timeline. We got to make sure any potential deal makes sense and certainly we will do that, but nothing has changed. To answer your question, we are still actively looking that that potential deal among others and we will explore that and if it makes sense, certainly pull the trigger and then address any changes in broad development or pace or anything like that at that time. But as we said -- like we mentioned, nothing is changing on our capital plan or otherwise production for the year, given what we've announced to date and then certainly we get any potential future deals done, including water, we will update at that time.

[Jeff Grampp:]

Okay. Understood. And on the ESP installation you guys did in Loving, I was just kind of curious how you guys kind of view that opportunities that if you have maybe off hand, how many of those mature, naturally flowing wells you have up there? And I guess not knowing what kind of production history you have on that, I’m curious if you guys can make any sort of assessment on it. Are these wells kind of establishing a newer higher curve or is that just kind of a shorter-term uplift and then things kind of track down to the fryer kind of trend line that it was after or just kind of curious how you guys do that longer term?

[Brian Ayers:]

Brian here. That is a great question. We are extremely pleased with the first well that we ran a pumping last month. We are not certain how the long-term impact factor is going to go, but I believe what we are going to see is actually a shift in the curve. I believe we are going to see oil with the pumps that we would not have seen. It's not quite certain how much yet. We are seeing a substantial rate increase and it seems to be very stable change. We have several wells drilled in 2014, '15 and '16 that I think are going to be -- it's great, great for this. So I think we'll see on the order of five or six more this year in the North. And if good, we could do a lot going into 2020.

[Jeff Grampp:]

Okay, great. And just real quick related to that, can you talk around what the cost is to put on an ESP there and is any of this kind of baked into guidance at all or would you guys say that’s potential upside if you continue to see this type of performance?

[Craig Owen:]

Yes, I think that your first part of that is the cost. Cost is on the order of $255,000 per well. As far as the volumes baked into guidance, I don't think they are. We knew we are going to do or test an ESP, but obviously not having seen those results in the North. We were -- we had something in there, but I don’t mean to say it's kind of fairly conservative on kind of what we -- what we could do, because we doesn't have any production history. So we will update that as we go on, but as Brian said, we got one well with ESP in the North and we will test others as we go and get more production history on this one.

[Jeff Grampp:]

All right. Sounds good. I appreciate the time guys. Thanks.

[Craig Owen:]

Thank you.

[Operator:]

Thank you. Our next question comes from Mike Kelly from Seaport Global. Please go ahead.

[Mike Kelly:]

Thanks. Good morning, guys. Craig, maybe you could give us a sense of where you guys are at on this water deal? And I’m just curious if you get a deal done, what’s the most likely use of proceeds or how does it potentially change this strategy at all in '19? Thanks.

[Craig Owen:]

Sure, Mike, and thanks for joining us. Yes, we’ve been working with our assets and certainly those on the tour now in the North, I think we mentioned in the call script that we got assets both in the North and the South. The North assets are more mature and that's what we're exploring potentially monetizing now. We are not exploring the South at this point. So where we are in that process, we started that before the end of '18. We’ve gone down the road quite a bit with a number of potential buyers that we’ve talked to over time, and that's in the dozens. So we -- I think we’ve canvassed the area pretty well. We will kind of continue that path and kind of narrow it down very quickly, but I think -- and again this is an if, because we haven't made the final decision, but if we do something it will be relatively quickly in the first half of the year and the use of those proceeds as we said, Mike, with this commodity price environment or pay down revolver and keep our plan as it is. Certainly as we get towards the second half of the year if commodity strengthens for example, we'd always want to be dynamic and be smart and kind of how we’re doing things. But as we think about it now the -- in the water sale monetization, those proceeds would be used to pay down our existing debt levels and kind of go from there.

[Mike Kelly:]

Okay, great answer. Thanks. And switching gears a little bit, the New Mexico acreage that you sold, and you may have touched on this in your prepared remarks, apologies if you did. But did you give us the acreage number in production that was associated with that? And then also curious what you have left up there? Thanks.

[Craig Owen:]

Yes, Mike, look to others in the room, we can't provide information on production data just with our agreement with the buyer. But this is all of our assets in Lea County that we are selling. And on the acreage, John or Brian may know that.

[Brian Ayers:]

880 net. It's in the mid 800's, Mike. And just in the production, we’ve been pretty clear that we just have the one well on that acreage back in July of last year. And if you look back, we provided the rates at that time. So you could probably look at that well and apply whatever decline you saw fit and kind of back into a production number that way.

[Mike Kelly:]

Perfect. Thanks, guys.

[Operator:]

Thank you.

[Craig Owen:]

Thanks, Mike.

[Operator:]

The next question comes from Eric Engel from Stifel. Please go ahead.

[Eric Engel:]

Hey, guys. Another follow-up question on the water business. You mentioned that you will do a deal that makes sense for the sale of the Northern Delaware basin water assets. What are some of the deal points or things that make potential deal makes sense for Rosehill?

[Craig Owen:]

Yes, Eric, thanks for the question. I think it always comes down certainly to, is it an economic deal, economic transaction that that makes sense from a valuation standpoint. And what it does to you on a go forward basis, do you have the -- do we have the right partner for example. If we can't move water, we can't move our production. So we want to be very comfortable with potential partner that they’ve got an operating history. They’re not something that was created yesterday, that type of thing. So that’s on the operational side. And then do the numbers make sense? We’ve got invested in that entire system roughly $25 million, so that and kind of what we agreed to on a go forward rate, all kind of comes into play. For example, I think we have this in our IR deck, it cost us roughly $0.30 or so to move and dispose for these water today. On a go forward monetization just like others have done, you agree to some higher rate for that. So you want to be able to live within that cost structure moving forward, it would potentially increase on a LOE rate, for example. So we want to make sure any of that makes sense, but ultimately it's valuation operator history, are we comfortable there and ultimately what does that do to your cost structure.

[Eric Engel:]

Thanks. Good answer. And then, you mentioned earlier also that you're going to be dropping a rig and then bringing it back this year. And I’m assuming that when you drop a rig and then bring it back you get a different rig and crew. How do you make sure that you're not losing any drilling efficiencies or am I thinking about that right?

[Craig Owen:]

Well, actually we are planning on doing that. We are going to -- let's say, our plan right now is to farm out a rig to somebody that’s pretty close to work where we’re at now and that will get us the same hot crew and the same hot rig back. So last thing we'd like to do is have to start up again in our Q4 and have a cold rig and a cold crew.

[Eric Engel:]

Okay. That makes sense, yup. That’s all I had. Thank you.

[Brian Ayers:]

Thank you.

[Craig Owen:]

Thanks, Eric.

[Operator:]

This concludes our Q&A session. At this time, I would like to turn the call over to Craig Owen, Chief Financial Officer, for closing remarks. Please go ahead.

[Craig Owen:]

Thanks, and thank everyone for joining the call today. We are pleased with the success we had during the quarter and what we’re able to accomplish in 2018. We’ve had a busy and productive start to 2019 and look forward to building on that momentum throughout the year. This concludes our fourth quarter earnings call. Thank you for your interest and have a great day.

[Operator:]

Thank you ladies and gentlemen for attending today's conference. This concludes the program. You may all disconnect. Good day.