Earthstone Energy, Inc. (NASDAQ:ESTE) Q3 2018 Results Conference Call November 8, 2018 11:00 AM ET
Frank Lodzinski - Chief Executive Officer
Robert Anderson - President
Mark Lumpkin - Executive Vice President and Chief Financial Officer
Scott Thelander - Director of Finance
Neal Dingmann - SunTrust
John Aschenbeck - Seaport Global Securities
Gordon Douthat - Wells Fargo
Jason Wrangler - Imperial Capital
Good morning. And welcome to 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 program is being recorded.
Joining us today from Earthstone are Frank Lodzinski, Chief Executive Officer; Robert Anderson, President; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Director of Finance. Mr. Thelander, you may begin.
Thank you, and welcome to our conference call. Before we get started, I would like to remind you that today's call may contain forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 as amended, and Section 21E of the Securities and Exchange Act of 1934 as amended.
Although, management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in our earnings announcement we released yesterday and in our quarterly report on Form 10-Q for the third quarter of 2018 and our annual report on Form 10-K for 2017.
These documents can be found in the Investors section of our Web site, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.
Also, please note information recorded on this call speaks only as of today, November 8, 2018. Thus, any time-sensitive information may no longer be accurate at the time of any replay. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's Web site, and also by telephone replay. You can find the information about how to access those on our earnings announcement released yesterday. Today’s call will begin with remarks from Frank, providing an overview on our activities and future plans, followed by remarks from Mark regarding financial matters and performance and concluding with remarks from Robert regarding our operations.
I will now turn the call over to Frank.
Okay. Thank you, Scott. And thanks to everybody for joining us on this call. We’re going to try to be a little brief today since the big news we announced three weeks ago was our pending acquisition of Sabalo Energy.
As a brief update, Tuesday of this week, we filed our definitive proxy and announced that we expect to have a special meeting of shareholders on January 3rd and will close very shortly, or immediately thereafter. We've already initiated actions to integrate these properties under Earthstone promptly and efficiently post closing and we are looking forward to a great 2019. Today, however, we will focus a little more closely on Earthstone as a standalone and overview of our third quarter financial results and operating activities before we open up our lines for questions.
Third quarter was a strong quarter for Earthstone, probably one of the strongest in our history or the strongest in our history. Our sales volume for the quarter averaged just under 11,000 Boe per day. Our revenues were more than $46 million and we reported adjusted EBITDAX of $26.1 million; after accruing a $4.8 million charge to income related to the settlement of a lawsuit, which we agreed to in principle in the latter part of October. I'm not going to elaborate on that matter other than to say the dispute arose over operations preceding our acquisition of Bold, and we're pleased that this matter has been settled and we can move forward. We’re actually finalizing certain agreements right now.
We believe the settlement will add drilling locations with longer laterals approximating 10,000 feet and allow us to accelerate development activities for this acreage. As I mentioned, we're currently finalizing the agreements. Without this non-recurring charge, our EBITDAX would've been over $31 million. Robert is going to address operations but I will just complement our operating folks and specifically point out that we continue to make significant progress on the cost side with our LOE per BOE down below our targeted $5 per barrel in the third quarter.
Apart from the announced Sabalo acquisition in the southern Midland basin, we continue to block up our acreage positions and build our inventory of locations with longer laterals as we demonstrated a month or so ago in our trade and acquisition in Reagan County, which gives us over 14,000 contiguous acres.
Let me just conclude by reiterating what we said a few weeks ago. The Sabalo acquisition is another transformational step for our company with an outstanding asset base of 21,000 contiguous acres, and a significant inventory of highly economic locations that can be developed with longer laterals. When combined with our existing acreage position, the acquisition provides us with significantly more scale and greater upside potential in the Midland basin. We're anxious to close this acquisition, as I mentioned, which is scheduled in early January. We'll efficiently and promptly integrate these assets to our organization and further demonstrate our capabilities to the market in 2019.
With that said, I'll turn the call over to Mark for a brief overview of our financials.
Thank you, Frank. Looking at our financial metrics for the quarter. As Frank mentioned, it was a very strong. From a top line revenue standpoint, sales revenue of $6.1 million increase both sequentially and year-over-year with the third quarter coming in at 23% increase versus the second quarter, and 47% increase versus the third quarter of 2017.
Production sales volumes in the third quarter hit a company record of 10,766 barrels of oil equivalent per day, or up from 8,845 per barrel equivalent of oil per day in the second quarter and compared to 9,671 barrels of oil equivalent per day in the third quarter of 2017. Our production mix remain relatively the same as in the first half of the year with a slightly higher crude oil component at about 65% crude with NGLs coming in about 19% and natural gas making up the balance.
Adjusted EBITDAX as we define it and report it was $26.4 million in the third quarter, which incorporated $4.8 million are accrued charge for the litigation expense below the operating income line that Frank mentioned. Without that charge, our EBITDAX would have been $31.2 million as compared to $20.5 million in the second quarter of '18 and $19.1 million in the third quarter of '17. In addition to increased sales volumes, a key driver of the increase in adjusted EBITDAX this quarter was lower cash SG&A charges, which do continue to track very well.
We reported net income of $0.6 million in the third quarter compared to net income of approximately $1.5 million in the second quarter of 2018, and net income of $4 0 million in the third quarter of 2017. As described in our previous earnings calls GAAP requires us to disclose the amount of net income associated with controlling interest, which essentially reflects our class a shares. Accordantly from a GAAP perspective, we reported net income attributable to Earthstone Energy, Inc. of $0.2 million or $0.01 per share compared to $0.7 million of net income or $0.02 per share in the second quarter and compared to $1.6 million or $0.07 per share in the third quarter of 2017. You can also refer to yesterday's release in our 10-Q for further information.
We do continue to focus on managing our cost structure as officially as possible, and we’re seeing continued reductions on per unit production basis on both our lease operating expense and cash G&A. LOE averaged $4.89 per Boe in the third quarter versus $6.22 in the second quarter and versus $6.08 in the third quarter of 2017. Cash G&A averaged $3.46 per Boe in the third quarter versus $6.48 per Boe in the second quarter and versus $6.30 in the third quarter of 2017.
The combined per unit LOE plus G&A of $8.35 per Boe is really a fantastic achievement for us, and meets our goal of hitting below $10 per Boe. And now it's tracking very well with our guided range for LOE per BOE and even below our guided range for G&A per BOE as reflected in our guidance.
With respect to our balance sheet and liquidity, at the end of the quarter, we had total debt outstanding of $35 million under our credit facility and a cash balance of $13 million, leaving us with net debt at the end of the quarter of $22 million, which compares to $18 million net debt at the end of the second quarter. This left us with liquidity at the end of the third quarter of a little over $200 million based on the $225 million borrowing base facility in place at the end of the quarter.
I will note that since the quarter ended, we announced the closing acreage trade in acquisition for approximately $28 million of cash, which we did fund largely with additional borrowings on our credit facility. And back to our borrowing base. Our lenders did increase the borrowing base from $225 million to $275 million this week. So our liquidity continues to remain very strong and grow in that basis. Our capital expenditures for the third quarter totaled around $37 million, which brings us on a year-to-date basis to approximately $120 million of CapEx.
From a hedging standpoint, I won’t detail out the hedges as is disclosed in the 10-Q and on slide and our investor presentation. But from a big picture standpoint, we've continued to add hedges over the past few months and a particular in anticipation of signing the Sabalo acquisition. We added a decent bit of oil swaps in early October at some really nice prices for 2019 and '20 volumes. And further I'd say we’re just planning to continue to layer on hedges as we get closer to closing the Sabalo acquisition and are actively looking to layer in swaps as we speak.
So with that, I will turn it over to Robert to review operations.
Thanks, Mark and good morning, everyone. As most of you are aware, we have accomplished a great deal since our second quarter call; we continued to effectively execute our one rig drilling program with solid performance from our new wells; we completed the acreage swap that both Frank and Mark have discussed a little bit that blocked up significant acreage position for us in County; and we announced the transformational acquisition of a large, high quality acreage position in the northern Midland basin.
Since we discuss the pending transaction in detail just during our call just a few weeks ago, I'm going to focus most of my remarks today on Earthstone's recent well results and current plans. Until we close the Sabalo transaction, which is expected to be early in the first quarter of 2019 and take over operations of their two rig drilling program, our operating focus will be on executing our one rig drilling program in the Midland basin where we are currently drilling in Reagan County. So in the third quarter, we completed a total of five wells.
One of the completions occurred in July in Reagan County on our WTG block, which was the last of six well completion program that was initiated in the second quarter. Since then, we completed three wells in Central Reagan County on our TSRH block and a single well on our Benedum acreage Upton County, which began flowing late in September and had no impact on our third quarter numbers.
We just finished fracking two more of WTG wells in southeast Reagan County, which we expect to begin flowing back as week. And the drilling rig has been busy during the quarter with these two WTG long laterals that we drilled and is now finishing up drilling on a three well pad in Western Reagan County on our Sinclair acreage. So, let me provide a little bit of color on each of these projects.
Early in the quarter, we drilled our well in Upton County on our Benedum block. As we mentioned our second quarter call, it was our first well in this area. And after drilling a pilot hole through the entire Wolfcamp section and logging it, we targeted the Wolfcamp B lower interval. In September, we completed this well with 7,453 foot lateral section and it is achieved a peak 30 day rate of 1,718 Boe per day with 90% oil. And we hold 100% working interest in this well.
In Reagan County, we drilled and recently completed a three well pad on our TSRH block where we have 100% working interest. This block is directly adjacent to the acreage we recently acquired through the trade. The average lateral length of these three wells is a little over 7,300 feet, and we drilled two Wolfcamp A well in one Wolfcamp B upper well. The wells began flowing back in October and we expect to reach peak rates within the next 30 days.
In the third quarter, we drilled two wells in far southeastern Reagan County on our WTG block. Both of which were Wolfcamp B upper well. We have completed both wells, which include our longest completed to-date of over 12,500 feet of completed lateral containing 72 stages. We will begin flowing back these wells this week. We have 50% and 41% working interest in both these two wells. These wells offset the Company's first B lower well in this block of acreage, which was completed in July of this year. In only 75 days of production, the B lower completion produced 111,000 barrels of oil equivalent, 90% oil from 10,339 foot lateral. The two recently three drilled wells also offset our 2017 completion of the Company's WTG 5-234 number one HM well, which was a B upper well, and it produced 95,000 barrels of oil equivalent being 80% oil during its initial 75 days of production from 9,300 foot lateral. So we have high expectations for these two wells we just completed.
In Western Reagan County where our drilling rig is working, we have just finished running casing on the last of the three well pad on our Sinclair block where we have 93% working interest. The average lateral length from this pad is approximately 6,700 feet where we targeted each of the Wolfcamp A, B upper and B lower. The averaged spud to rig release across these three wells of 13.5 days per well, so congratulations to our operations team once again for their efficient execution. And we will begin fracking these three well pads later in November.
You may recall that we had completed a B upper and a B lower well in 2017 in the Sinclair block. And as we have previously discussed, these wells have an average EUR of approximately 850,000 Boe from average lateral lengths of about 7,900 feet. Following this pad, the rig will move to our Malone unit in Central Reagan County where we have 100% working interest. So with our activity in the first three quarters, we expect to end 2018 with 15 to 16 wells drilled or drilling, and 19 wells being completed on our Midland basin acreage through the year. In the Eagle Ford, we are planning our next group of wells in southern Gonzales County on our Penn Ranch unit, where we have 25% working interest and control operations. The timing of this drilling may slip into 2019 due to the lack of suitable rigs at the current time.
On the cost side, as Mark has mentioned, we've done an excellent job of managing LOE. We have resumed the trend of lowering LOE per BOE as our production increases. However, I would like to mention one benefit of the recent trade that we did in Reagan County is that we swapped out non-operated wells for operated wells, which contain a number of vertical locations in the non-operated side and we will continue to have the trend of decreasing LOE by trading away these higher cost vertical wells that range from $11 to $12 per Boe of lifting costs compared to horizontal wells that average below $5 per Boe.
Throughout the fourth quarter, we will be preparing to assume operations of the Sabalo acreage integrate the data and implement day-to-day operational oversight. Some of their staff will assist with this transition for a few months, but we are very confident in our ability to integrate their operations efficiently and make a smooth transition. We have continued expanding our operations team just this year and as we have done in prior companies, we will effectively and efficiently manage a multi-rig drilling program. Expanding our scale and having a dedicated completion crew is going to allow us to make meaningful improvements in cost efficiency and operational efficiency. Between blocking up of our acreage in central Reagan County and adding about 21,000 contiguous net acres in the core of the northern Midland basin, we have dramatically expanded the number of drilling locations that are suitable for longer laterals. So in 2019, we should see lower costs and higher performance from our operations and of course much higher production.
We are working through drilling plans with Sabalo to evaluate options for drilling significantly de-risked lower Spraberry and Wolfcamp A formations, along with progressing the delineation of the Wolfcamp B and new Spraberry, which are being successfully developed by offset operators. And we are excited to be in a position to develop this high quality asset. We will continue to be active, however, in acreage transactions and trades where we can add to and enhance our operated positions and further grow our inventory.
I will now turn it back over to Frank for some concluding comments.
Okay, thank you, Robert. So before we turn it over the questions, there is a couple of concluding remarks. First, I do want to recognize the staff here. You folks on the line can tell that we've been awful busy throughout the year and particularly here in the third quarter and since. We've accomplished a number of important objectives that we advised the market over the course of the last year that we were working on.
Our position in the Midland basin are post closing will be over 50,000 acres. And some of you that are new to Earthstone I will tell you that in early '16, we had zero acres in the Midland basin and no production. We are executing well on our operations and we’re going to continue to make that a focus and we progressed with all of our objectives to-date. So we're looking forward to 2019 being a great year for Earthstone and we're anxious to get started.
Operator, we'll now take questions. Thank you.
Thank you. Ladies and gentlemen, at this time, we will now be conducing our Q&A session [Operator Instructions]. Our first question comes from the line of Neal Dingmann from SunTrust. You're now live.
Robert, could you remind me on Sabalo, I know there's a lot of potential formations or zones there and you all -- Frank did the value and Mark did the valuation on that. I guess my question is around what were you -- assigning value and what will you start to drill and really focus on initially.
So the lower Spraberry in Wolfcamp A and the production carried the valuation to get to the purchase price. However, there is significant upside in both the Wolfcamp B, which is being developed to the east. You can go look at the Sundown well without east and there is an Eastland well out east, both in the Wolfcamp B that have very good results. And then the middle Spraberry, it's a little bit to the west of the acreage position. Our focus early on is going to be the Wolfcamp A and the lower Spraberry, and we’re looking forward to middle Spraberry some results in testing early in the year of 2019.
And then just my last follow just on -- it might be premature. But I know you've talked about running three rigs when you and Frank look at this, do you already know where those rigs will be running and where the focus will be '19? Or is that still a bit up in the air depending on how the wells turnout?
Generally speaking, yes, we know where the rigs are going to be. We're going to have two on the Sabalo asset and one, generally speaking, in the southern Midland basin. The definition of exactly which units we're drilling, we're working through that right now. But we do have some obligation drilling that will be first and foremost on our list and then beyond that, we'll have a bunch of discretionary opportunities to pick and choose where we want to go.
Thank you. Our next question comes from the line of John Aschenbeck from Seaport Global Securities. You are now live.
For my first one, I would just like to get your thoughts -- a follow-up on '19 actually. Just give your thoughts on how you approach your development program with respect to different commodity price sensitivities scenarios. So your acreage is predominantly HVP. So you certainly don't need to drill many wells. And if you had to, you can toggle down activity. So just trying to get a high level thought on when you look at the development program you have laid out there for the combined company and at what price point do you start to look to bring in activity?
We're all trying to put the coin to answer the question, John. So somehow I threw the short straw. I'll tell you one thing that, as you know and as most of the industry has recognized. This basin is probably has the lowest breakeven cost. So even though you maybe wouldn't want to drill in $40 price environment a lot of our locations still have very good economics at $40. And that's greater than 10% rate of return, how about that. But I think I would say that if we start getting into the 40s, we can ratchet back our CapEx program and focus on our obligation drilling, which combined company will be 20 wells total. So we're looking at less than a rig and a half of time to be able to maintain our obligations, and that's without doing any land trades or working with owners to extend leases and obligations.
So I might just add from a price standpoint, we like where our prices are a whole lot right now. And really right now 2019, the strip is about 63 for WTI and the mid cush strip is about $5. So you can lock in hedges that are about $58 right now. We're continuing to actively do that and get a bigger slice of our 2019 production hedge. We like that price a lot. When we're looking to Sabalo acquisition and really game planning the rig program and the financing and everything, we were looking at higher WTI, but a wider mid cush that was coming up pretty similar . So we feel really good about where prices are right now. Granted we liked it better a month ago when the strip was 73 and we did lock in some barrels then, but that was well above what our assumptions were and we like prices a whole lot right now.
And so then for my follow-up in terms of operating cost, you guys had a big improvement this quarter on a per unit basis specifically. Sounds like a part of that benefit is just swapping out some of the high cost vertical non-op wells, Robert that you mentioned. But I was curious if there's any other major drivers at play in terms of cost savings or anything you guys are doing internally and if so. What could those be?
Well, we actually didn’t get that trade done until early in October, so it had no impact on Q3. So I'll say that our guys in the field spend a lot of time focusing on where we can cut costs constantly. And we've moved a couple of wells to rod pump from gas lift when they reach the appropriate time. We spend a lot of time making sure that when we go fix a well that we are not fixing it just for a month or two that we fix it permanently. We're not putting a band-aid on things, so some of those things that we've done in the past and we continue to do have just continued to impact on a go forward and improve our margins. So I don't know that there's any one event, it's just a constant focus of our field guys to watch over operating costs.
We've never -- you'll probably recall. But we've never really subcontracted operations to pumping services or to roustabouts and things like that. We build our staff and we have been doing that for 20 years and some of the people out there have actually worked for us for 20 years. So when you're looking at this type of acreage and the manufacturing aspect, sometimes on the front end, you have to incur fixed cost in terms of facilities, personnel and all of that kind of thing. And what happens is as you add additional production, sure you may have some additional fixed costs, but you are adding more variable costs. So the trick is to build the production and keep the cost under control that we've done in the past and that ranges all the way from electricity, to pumping units, to personnel, to minimizing downtime and so on. There's no one single item.
And maybe just a quick follow-up on that, I'm not sure if you have it handy I may be getting too granular here. But how much lower on a BOE basis when you think of your horizontal LOE cost relative to your vertical cost, how much lower are those costs? So doesn’t have to be too precise? I'm just trying to get a feel for the potential cost-benefit you could realize as you continue to swap out higher cost non-op wells?
Well, like I mentioned in the remarks, John. These wells we traded out of average about $11, $12 per barrel, there is a few horizontal wells in there but not very many. And our horizontal wells are averaging less than 5 bucks a barrel. So, there's a $6 gain in there from trading out of vertical production into horizontal.
[Operator Instructions] Our next question from the line of Gordon Douthat from Wells Fargo. You're now live.
Just wanted to get your thoughts on how you look to run the business here now that you've made a sizable acquisition that I know you've been looking for some time. Just wanted to get a sense on are you looking more towards the shift in strategy towards optimizing efficiencies and development? Or still looking to couple that with additional fill-in acreage? So just wanted to get your thoughts on if this is possible…
Well, that’s all in process. Gordon, this is Frank. We've been doing this a long time. And to be totally straightforward, I think that sometimes the whole scale element that's out there in the market is overplayed for a company like us based on our past performance, because we can achieve comparable results to some of the other folks out there that have bigger operations and pricing power and this, that and the other thing, because we don't have -- I am being tacky here. But six layers of bureaucracy we're pretty flat organization.
Now that all said, if you take a look at our map and you take a look at press release we put out a month ago on this acreage trading, blocking things up. Obviously, if we can continue to extract all the nickels and dimes out of D&C and operating costs then the next going to lead to greater reserves, increased gross margin, lower LOE per Boe. So if you take a look at the Sabalo acreage, we've got a really nice chunky blocked up acreage that our operations' guys can't wait to get their hands on. And if you take a look at our other holdings, although, they're very good, they're spread across three, four, five, six different counties, so right now, our thinking is continue to block up.
And this is a moving target but generally speaking. Continue to block up acreage that we have in Reagan and Upton County; continue to trade our products or ultimately divest non-operated positions; we've always operated more than 75% or 80% of what we've done historically. And then if our operations' guys can do what they demonstrated over this company and in the prior companies, extract all those nickels and dimes. So hopefully, we’re going to look for a chunkier position, less diversified acreage, which I call scattered, to be candid with you, although, all the economics are good on these things.
And so that's the vision for the next year, as well as doing another big acquisition, we might as well throw that gauntlet down to our guys if we can do a value-based merger, acquisition or something along those lines.
And then just with respect to the acreage phasing that you've had, particularly in Reagan County. What's the potential there for longer laterals and potential efficiency gains that might be add as you blocked up that position?
Well, we’re still working through that, because the trade has been only done for a month. We’re trying to integrate that into our combined plans with the acquisition that will get closed in early January. So, I'll just tell you that we have ongoing plan of increasing the potential for longer laterals. And as Robert mentioned, we just did our first 12,500 foot. So I'd like to see a lot more 9,000 and 10,000s than 7,000s and 8,000s, going forward. What's the potential? These things take time. I mean the trade we did here a month ago and took a long time to get done. But the real positive thing as all you folks know is that there are people in the midland basin who want to do these types of trading so long, because everybody is looking to maximize lateral length and so on. So we're just going to keep working on it on a daily basis.
Thank you. Our next question comes from the line of Jason Wrangler from Imperial Capital. You are now live.
Just wanted to ask as we get closer to the closing of the deal, as you think about the infrastructure and obviously adding quite a bit of it. Going forward, where should we think about the infrastructure spend? Or where do you think the position is in terms of [Indiscernible] versus what you guys were talking about…
There's always additional infrastructure that our guys want to make their life easier and sometimes we'll allow for that and sometimes we're going make them keep working hard. We probably have plans both on the Earthstone asset, as well as Sabalo assets to add some water disposal infrastructure every time you bring a new well on, you add to that volume of water you're disposing of. And so we've got some plans next year. But you've seen that guidance of $425 million to $500 million of CapEx, still be a very small percentage of that total CapEx number in 2019.
And then maybe just, Frank, you were mentioning as far as trading out the non-op and into the upper. However, that portfolio management, so to speak, is going to happen, which you guys have been doing for a while. Is it fair to think that you guys are base seeing this around the Reagan and Howard assets and you can continue to build there? Or it is there somewhere else that we should be thinking of that's a candidate either to expand or contract throughout the position?
I think our first order of business will be to maximize the acreage and enhance the acreage positions while we already have positions. So that would tell you that our focus will be in and around Howard County what we already are. If there's an opportunity to pick-up another sizable acreage block and I don’t know what I mean by that. But I don't want to go to southern Howard County for 600 acres. But if it's a block of a few thousand acres that can be effectively drilled has potential, we will consider that. But I think for right now we're going to look in and around where we are and continue to try to block-up acreage, principally in Upton and in Reagan County, and our southern operations, and our non-Howard County operations. Robert, what do you think...
No, that's what we've were focusing on is beefing up our acreage position in around where we have sizable blocks already. But Reagan and Upton would be a great place to add, both not only from economics of well but operating efficiency and being able to share infrastructure like SWD in a smaller area.
That’s helpful. I'll turn it back. Thank you.
Well, it looks like we've run out of questions here. I hope that's a function of us putting our good information for people and not a lack of interest. I know we had a lot of interest couple of weeks ago. We're going to continue doing what we're doing. We'll the market advised. We'll put out press releases and of course, if any of the investors or analysts have questions, we are pretty transparent, give us a call. And with that, operator, we are finished. And thank you to all.
Thank you, ladies and gentlemen. This does conclude our teleconference for today. You may now disconnect your line at this time. Thank you for your participation and have a wonderful day.