Earthstone Energy Inc (ESTE) 2018 Q2 法說會逐字稿

Good morning, and welcome to Earthstone Energy's Conference Call. (Operator Instructions) As a reminder, this conference 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 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. 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 the earnings announcement we released yesterday and in our quarterly report on Form 10-Q for the second quarter of 2018 and our annual report on Form 10-K for 2017. These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risk 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, August 7, 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 website and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday.

Today's call will begin with remarks from Frank, providing an overview of 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'll now turn the call over to Frank.

Good morning, everybody, and thanks for joining us. While we had a solid second quarter, our results were clearly influenced by our decision to reevaluate our Midland Basin development program, primarily due to industry and market conditions related to take-away capacity and Midland Basin differentials. At present, we're having no problems with take-away capacity. And as Robert and Mark will discuss, in consideration of both economics and acreage capture, we directed our operated drilling rig to certain locations where we have drilling obligations and are trying to accelerate certain land trades that will result in longer laterals. In addition, certain completion activities were delayed for a little bit. At present, we only have to drill 3 to 5 obligatory wells per year starting in '19 -- 2019 and beyond.

We did conclude in July an 8-well completion program. All of these wells are performing as expected and meeting or exceeding our time curves -- our type curves. I'll let Robert and Mark tell you about initial production results and so forth.

As we mentioned last quarter, one of our primary objectives is to efficiently schedule well completions, so that we often group 6 to 8 wells to effectively deploy our nondedicated but recurring frac crew. Our goal is to achieve high-quality results at reasonable costs.

While this can create some lumpiness in our production profile, it is an issue that will smooth itself out as we continue to grow and have a larger base of production and a higher level of activity.

Considering the differentials and the other constraints in the Permian basin, we thought it appropriate to adjust our capital spending. At the moment, we think it's better to be a bit conservative rather than aggressive, which is why we have not yet brought in a second rig into the Midland Basin.

Given our very good well results and strong economics, at present, we're planning to deploy the second rig, hopefully, as early as the end of '19 or very -- I'm sorry, the end of '18 or very early '19 when we expect more direct visibility to increase take-away capacity out of the basin. Mark will discuss in more detail as outlined in our press release, but we are adjusting our guidance and our 2018 capital program and full year production based on the current environment.

Certainly, growth is very important to us, but there is no need to accelerate solely for the sake of production growth. We also remain highly focused in pursuing growth through acquisitions. We continue to see excellent opportunities and we are as optimistic as ever that we can continue to enhance our acreage position and hopefully complete a transaction to meaningfully increase our Midland Basin footprint and production profile.

I'll now turn the call over to Mark for a brief overview of our financials.

Thank you, Frank. Looking at our financial and operational metrics, the second quarter results generally represent a moderate decline compared to the company's record first quarter results. And this is driven largely by the timing of our completions. Our sales volumes in the second quarter averaged 8,845 BOE per day compared to 9,664 BOE per day in the first quarter and compared to 7,932 BOE per day in the second quarter of 2017.

Our production mix remain relatively the same as in the first quarter consisting of about 63% crude. NGL production was slightly higher at 19% compared to 17% with natural gas making up the balance. Adjusted EBITDAX was $20.5 million in the second quarter of 2018 compared to $25.3 million in the first quarter and compared to $13.3 million in the second quarter of 2017.

Our pipeline revenue for the second quarter was $37.2 million compared to $40.9 million in the first quarter of '18 and $25.8 million in the 2017 second quarter. The decline in revenues reflected our lower production volumes, which was partially offset by stronger realized crude oil prices.

We reported net income of $1.5 million in the second quarter of 2018 compared to net income of approximately $12.2 million in the first quarter and compared to a $55 million net loss in the second quarter of 2017, which did include a $67 million asset impairment charge.

As described in our last earnings call, GAAP requires us to disclose the amount of net income associated with a controlling interest, which is essentially reflects our Class A shares.

Accordingly, from GAAP's perspective, we report net income attributable to Earthstone Energy, Inc. of approximately $0.7 million or income of $0.02 per share. That compares with net income of $5.3 million or $0.19 per share in the first quarter of '18 and a net loss of $17.1 million or a loss of $0.75 per share in the second quarter of 2017. You can also refer to yesterday's earnings release and our 10-Q for further information.

We continue to be focused on improving our cost structure and on a year-over-year basis, we produced both our consolidated lease operating expenses and cash G&A expense on a per BOE basis by about 4% and 9%, respectively. On a per equivalent barrel basis, LOE averaged $6.22 in the second quarter compared to $5.35 in the first quarter and compared to $7.26 in the year prior period of 2017. The increase in the LOE per BOE is largely driven by the quarter-over-quarter decline in production sales volumes, and we expect to resume our trend of lowering LOE per BOE as our production growth picks up again, as was already happened in the fourth -- third quarter with company average estimated production for the month of July of around 11,500 BOE per day.

With respect to our balance sheet and liquidity, at the end of the quarter, we had total debt outstanding of $22.5 million under our credit facility and a cash balance of $4.2 million, leaving us with net debt at the end of the quarter of $18.3 million. Also during the quarter, the borrowing base on our reserve base credit facility increased from $185 million to $225 million, which increased our liquidity to about $207 million at quarter end giving us ample financial flexibility.

Our capital expenditures for the quarter totaled around $52 million, which brings us on a year-to-date basis of approximately -- to approximately $74 million of capital expenditures. As Frank alluded to, we've been drilling and completing at a slightly more measured pace than implied by our prior guidance, having spent CapEx in the first half at a rate below our annualized guidance. We have lowered our CapEx guidance for 2018 to a total of $140 million versus our prior guidance of $170 million, and we expect to put 19 wells on production in the Midland Basin and spud 15 wells both on a gross basis in the Midland Basin for 2018.

Also consistent with the more measured pace of our CapEx spend, we are lowering our range of production guidance to 10,500 to 11,000 BOE per day, which is down from our prior guidance of 12,000 to 12,500 BOE per day. We still expect average production mix in 2018 to be about 64% oil, 19% NGLs and 17% gas. Also on a lower assumed production base for the year, our unit LOE per BOE is now projected to be in the $5.25 to $5.55 -- $5.50 range, up from our previous guidance of $4.75 to $5.25.

Despite the lower production base, we're maintaining our per unit G&A costs at around -- at $5 to $5.50 per barrel as our G&A has been held in check and year-to-date is tracking very well. Our goal for 2019 for both LOE and G&A on a per BOE basis is to get below $5.

From a hedging standpoint, we continue to layer on hedges to mitigate the impact of price volatility. And in addition to the swaps from the underlying oil and natural gas production, we've added a significant number of basis swaps to protect our cash flows from volatility in the Midland Basin differentials on our Midland Basin oil production and also to take advantage of premium pricing on our Eagle Ford assets, where we receive LLS pricing.

For the second half of 2018, we have around 4,700 barrels per day of oil hedged at a price of $54.31 per barrel. We also have 2,650 barrels per day of basis swaps for the second half of '18, which includes 1,650 per day of Mid-Cush swaps at a discount of just $0.15 per barrel and 1,000 barrels a day of LLS swaps at a premium of $6.35 per barrel.

For 2019, we have 3,450 barrels per day of oil hedged at a price just over $57. And we've got total basis swaps of 3,500 barrels a day, which is comprised of 2,500 barrels a day of Mid-Cush swaps at a discount of just over $7 a barrel and 1,000 barrels per day of LLS swaps at a premium of $4.50 per barrel.

And finally, for 2020, we have 1,000 barrels a day of oil basis swaps at a discount of $5.95 per barrel. Please refer to our earnings release and 10-K for further details. Also, the hedge schedule is laid out, [where] we did put some hedges on post end of the quarter that are reflected in the press release and Q, but perhaps more easy to read in the investor presentation as they're summarized a little more efficiently there.

I would also just point to the investor presentation we put up yesterday afternoon, which there are a few updated slides, largely just updates, but it does include some updates on production versus our curves on Page 20 as well.

With that, I'll turn it over to Robert.

Thanks, Mark. As Frank mentioned, our one-rig program is operating in the Midland Basin to delineate and develop our 20,500 net operated acreage.

In addition to being pleased with well performance, we are improving the efficiency of our drilling operations, and I'll highlight some of those statistics for you first. Although we are currently drilling 1 to 2 well pads and losing some efficiency in rig moves between pads, our last 7 wells achieved spud to total depth in an average of just under 13 days with an average lateral length of 7,706 feet. For the same group of wells, we had a spud-to-spud average of less than 20 days, which includes time to run the production casing, cement, rig down all the equipment and physically move the rig. In this spud-to-spud average, we had a couple of moves that took 7 days and 10 days, whereas they should have taken 4 to 5 days, a direct result of the trucking issues related to the basin.

So the overall pace of our one-rig drilling program was affected by these trucking issues. The service industry, particularly, trucking, as you all know, in the Permian basin, is way overloaded, making it difficult for us to timely move our rig between locations.

Regarding completion efficiency, it is all about the number of stages per day. In this round of completions, we started out at under 6 stages per day on our first pad, but by the time we completed our program in July, we averaged 8 stages per day on our last pad. As we have always done, we will build an inventory of wells to frac before bringing in the various services associated with the completion, which is much more cost effective than trying to do one pad at a time at a one-off well.

Our latest completions in the Midland Basin included the group of 8 wells, with 2 in Midland County and 6 in Reagan County. We completed wells in the Lower Spraberry as well as 4 distinct Wolfcamp reservoirs. The 8 wells averaged a little over 6,000 -- 7,630 feet of completed lateral length with 48 stages and over 2,500 pounds of proppant per foot.

In Midland County, we completed 2 wells in our Hamman project, where we have a 70% working interest, one in each of the Lower Spraberry and the Wolfcamp B. The wells had an average peak 30-day rate of 1,170 barrels of oil equivalent per day with 88% oil from an average completed length of 6,842 feet.

After 2 months, these 2 wells have cumulative production that is 7% higher than the 2016 wells completed on this acreage from the same benches.

In our WTG project in Southeast Reagan County, where we hold a 100% working interest, we have just completed our first Wolfcamp B lower well in this area. Although this well has only been online since the middle of July, it has produced at rates above 2,000 BOE per day with 93% oil from a 10,339 foot lateral. It is tracking the WTG B upper well we completed in early 2017 that has an estimated ultimate recovery of over 1.1 million barrels of oil equivalent, which been -- which has been assigned by our third-party reservoir engineer.

The Wolfcamp A well on this same pad is continuing to increase in oil cut, which is typical of the A reservoir in Reagan County, but has yet to reach a peak 30-day rate.

We realize that everyone is interested in hearing about the Wolfcamp C well we drilled, but we don't really have enough data yet to report a clear conclusion. Nevertheless, we have completed our 2 well West Hartgrove pad, where we have an 87% working interest in the Wolfcamp C and Wolfcamp B Upper well. These 2 wells average 5,785 foot laterals. The Wolfcamp C has produced at rates as high as 995 BOE per day, 77% oil. So it's an encouraging start.

The Wolfcamp B Upper on the same pad has produced at rates up to 1,267 BOE per day with 86% oil. While both wells are still flowing, we are restricted by commercial saltwater disposal capacity at this time. Our current plan is to put these wells on electric submersible pump as the flowing pressure declines.

From a performance comparison, the Wolfcamp B Upper well is producing in line with our 2 wells at our Sinclair block, just a few miles to the east of this West Hartgrove block. We completed a B Upper and a B Lower in 2017 in the Sinclair block. And these wells have an average EUR of approximately 850,000 BOE from 7,892 foot laterals, whereas this new well is producing very similar, but from a much shorter lateral.

The other 2 wells we brought online during the second quarter had to be shut in for 20 days due to lightning, knocking out the electrical panels, servicing our company-owned saltwater disposal facility. The wells are now back online and though we are encouraged by the rates, we do not have peak 30-day results just yet.

This has been a long-winded way of saying that we're very pleased with the recent drilling and completion efficiency as well as the early performance of these 8 wells. And as Mark stated, our July production estimate is just under 11,500 BOE per day and that's aided by the success of these recent wells.

Our rig is continuing to operate in Reagan and Upton Counties, where it will likely remain for the balance of the year. We will continue targeting the Wolfcamp A and B formations in this area. The rig is currently drilling on our Benedum block in Upton County, where we hold a 95% working interest. Since this is the first well in this area for us, we drilled the pilot hole through the entire Wolfcamp section in order to better understand the multiple landing zones available to us. We -- and we have chosen to drill this well in the Wolfcamp B Lower interval.

As mentioned, we are planning for a second rig either later in the year or early in 2019 as we anticipate having more visibility on take-away capacity. Even with 2 rigs running, we would expect to build up an inventory of wells to frac before starting our completion program. As a side note, because of a scheduling opportunity with our frac company, we began a smaller completion program last week that will allow us to complete a 3-well pad in August. After this, we should begin completions on additional 7 wells throughout the fourth quarter with the majority of these coming online before year-end.

Clearly, we are being impacted by the negative differentials in the Midland Basin, but the economics continue to be very attractive at current oil prices. With all of the crude oil from our properties being trucked, we have always and will continue to utilize multiple purchasers in order to maintain diversification of our take-away needs and keep multiple options available at any point in time.

We have a continuous dialogue with our purchasers to make sure we have our barrels headed to market versus sitting in tanks. We have not had to shut in any wells, nor do we anticipate doing so. We made it through this round of new completions, where oil rates are highest in the first few months with no issues. We are, however, investigating options for crude oil pipeline gathering, but have not reached any conclusions at this point.

We remain extremely enthusiastic about the economic returns in the Permian and are actively working to grow our footprint in the basin. Our past efforts to maintain our balance sheet strength and create strong liquidity has positioned us well to pursue opportunities that we think add significant value and can take us to the next level in the basin.

Just a short comment on the Eagle Ford. We started a 5-well program on the Sayre pad on our Southern Gonzales County acreage in late March, where we have approximately a 17% working interest and operations. We completed the wells in mid-July, and all of the wells are now flowing. As you can see from our press release yesterday, the wells are flowing with good initial rates and high oil cuts. We are pleased with the results of these new wells as they are performing in line with our 2017 completions in the offsetting Pilgrim and Davis Units. We are still on target to drill a total of 12 gross Eagle Ford operated wells and put 16 gross wells on production in 2018. And we are preparing for the rig in the fourth quarter on our Penn Ranch Unit, where we have a 25% working interest and operations.

With our comments today, we've tried to demonstrate that we have a deep inventory of highly economic operated drilling locations in the Midland Basin and our continued focus on efficiency gains are making these economics even better. As is our strategy, we're working on several avenues for expanding our inventory, including through the drill-bit where we're exploring some drill-to-earn opportunities, acreage trades that are in the works and acquisitions -- asset acquisitions of various sizes. This -- there is still a good level of acquisition opportunities for us to consider in order to achieve our growth objectives.

And with that, I'll turn it over to Frank.

Okay. Just to wrap up before we take some questions. Hopefully, you'll realize that we are being proactive in our operations in light of the issues, market and industry issues related to take-away capacity, differentials, services, et cetera. As many of you know, we have experienced these types of situations in the past, and we always come out of it looking pretty good. I do want to reiterate that we are having no issues right now with respect to take-away capacity. We are in constant communication with our purchasers, don't anticipate any take-away issues. But, of course, the market is going to drive all of that. We've never had to shut in any wells, and I don't anticipate having to do so in this environment. We'll continue to seek opportunities on the M&A front and look to grow our company cost effectively. Operator, we'll now take any questions.

(Operator Instructions) Our first question comes from the line of Brad Heffern with RBC.

I was hoping you could talk a little bit more about the water disposal issues. Obviously, that issue with the lightning strike seems like it was just a onetime event. But is all that is currently constrained by the water issues that 2-well pad? And do you see any other issues with disposals as you go forward with your plan?

Brad, this is Robert. No, no other issues. And it is only related to those -- that 2-well West Hartgrove pad. We're looking into some other options of trying to get a third -- we have 2 commercial disposal wells that we're going to and we're actually looking to go to a third one perhaps. It's going to cost a little bit of money to tie it in. But we're evaluating those options. So it doesn't really affect anywhere else. And like you say, the lightning strike was a onetime event that unfortunately set us back a month basically, so.

Yes. Okay. And then these Wolfcamp B wells in the WTG area seem really strong. Can you talk about how many locations you have there in the B? And then is there any chance that you're draining more than just the Lower, the Upper with those wells? Is it -- do you think it's likely that you can stack wells in that interval?

We believe we can stack wells in that interval. We haven't done that exact test yet, but we have drilled in the B Upper and the B Lower. And part of the reason we think we can do that is because of thickness, have quite a thick interval there in the entire Wolfcamp B package. So that definitely helps. From a location count, we're about 1, 2, 3, 4 miles wide and 660 foot spacing. And we've got half a dozen wells total drilled down there. So you can kind of back into the math of the number of locations.

Robert, is it right to tell the audience that in our PowerPoint presentation, we show how the Wolfcamp thickens across the basin going down into Reagan County?

Absolutely, I was trying to find the exact page.

Trying to find that page, Brad.

I think it's on Page 14 and 15 are the ones that actually highlight that, so 15 is the actual [time] section.

Okay. And then last one from me, just thinking about basis and the pipes getting more full as we go through the year. I'm just wondering is there a price that you guys have as far as what you're realizing in Midland, where you might think about deferring the completion crew for the fourth quarter and sitting on some DUCs for a while? Or yes, is there a price in the low 40s or something like that where you might think about that?

I don't want to be a smart aleck, but ask us on the next call as we get closer to that. We continue to be -- I continue to be -- this is Frank, continue to be impressed by the results we're seeing in these wells, they're quite economic. It's a juggling act right now. We've talked to every purchaser out there, we've had the benefit of having very large scale purchasers and transportation companies come in here. Our feel is that if you look at it, there has been no capacity, there are no capacity issues currently. And we seem to be getting a flavor that pipelines are going to come into the area sooner rather than later. And the last thing I want to do is lay down a drilling rig. Once you got the machine working, you got the machine working. So we're scheduling to go into this next 7-well completion program in the fourth quarter, and prices are going to dictate that. I apologize I just don't know how to answer that any better.

Brad, just following up on that, this morning I was looking at what the strip looks like next year and what the kind of basis differentials you could hedge it at. And right now, you could hedge 2019 and '20 for that matter as well at kind of a net WTI minus the diff price of right at $60. Yes, obviously, it looks worse between now and the end of the year. But like the reality is, part of these completions are going to come on and we're going to suffer some of the differentials just like everyone. A good chunk of that you get into '19, you can kind of swap that and get kind of a level price for the year and kind of smooth things out a little bit that way, too.

Our next question comes from the line of Neal Dingmann with SunTrust.

Robert, for you or Frank, where you don't have the full '19 or in the guidance out there. But could you talk little bit about, you mentioned your Eagle Ford release today where you plan to drill the additional 5 to 7 wells later in the fourth quarter? Do you continue drilling there despite more, call it, reallocation and continue to slow down in the Perm if sort of things continue or how do you see the sort of end of the year beginning of next year play out, I guess, is my question?

Neal, we've got a few obligation wells for '19 in the Eagle Ford. And then, we got another area in the Eagle Ford that we don't have any obligation that we could go drill some wells. I think ultimately, at the end of the day, when we get into '19, even with the differentials, our economics in the Midland Basin are going to be superior. So it's a matter of spending a little bit of capital in the Eagle Ford, but not necessarily allocating tremendously more. If we tried to do it right now, I'm not sure that the benefit between now and the end of the year has -- is that great for us given that we think the differentials are going to improve in the Midland Basin during '19.

So I guess, that kind of goes to my -- just my follow-up as far as when you and Frank look at bolt-ons any sort of acquisitions, trades or whatever you might see, the thought is still prefer Permian over Eagle Ford because of these returns?

That and operational efficiency, if we can tack on a few acres here and there and get longer laterals or surface operations becomes a scale issue where you can really drive down your costs. Both of those things are impacting how we look at acreage opportunities in the Midland side of it.

Yes, the economics are just strong and obviously this is a -- hopefully a temporary phenomenon out there, but I think it would be poor -- frankly, we've made our bed and we're going to sleep in it. And the Permian basin is our focus going forward. And I'm gratified that the operations are going so well and the economics look really strong. Mark, what was -- did you throw out what that -- what you could hedge basis differential next year for -- is it $6, $8?

It's just under $6 this morning.

Yes, it's just under $6. So if you're seeing north of $60 with a $6 basis swap, that's really strong economics out there. So this is a fluid situation, Neal, and you've known us for a long time. We'll keep working that equation.

Our next question comes from the line of John Aschenbeck with Seaport Global.

I was wondering as you think of adding the second rig by the end of 2018. I was wondering how we should expect the completion cadence to follow. And Robert, you kind of touched on this in your prepared remarks, but would that second rig essentially be building a DUC backlog for the first half of the year in 2019 and then you'd have a heavy second half of activity or completion activity?

Yes, that's pretty much -- I mean, it's hard right at the moment to kind of schedule all that out, but that's kind of the way we think about it. We'll pace our completions based on when we can get a frac crew and then keep them busy kind of all the time, subject to maintenance shutdown. But once we get 2 rigs and a backlog of inventory then we ought to be able to maintain a -- one frac fleet almost permanently.

Okay. Yes, so that was going to be my next question. Once you do have the 2 rigs going full time, you could essentially support a full time completion crew?

As long as we've got an inventory to start with. The frac guys can run ahead of the drilling guys, generally.

Okay, great. Appreciate that. And then in the Eagle Ford, it looks like your recent activity is focused on Southern Gonzales and Karnes Counties. I was wondering if you have any plans to move back to North Gonzales and Fayette, because some of your peers in the area have had some interesting results. I was curious if you have any plans to test any new concepts on your acreage.

Well, like I mentioned to Neal, that would be something we would look at in 2019 as a portion of it would be in Southern Gonzales and a portion would be right along the Fayette-Gonzales County line, if we continued a drilling program in the Eagle Ford in '19 to any degree. We have a few locations up there, like you say, are offsetting some recent results that with some changes in designs and lateral lengths increasing the results look very attractive, so.

Yes, up there we have a 50% interest in operations. There, we haven't drilled a well -- drilled or completed a well out there, what, in 2 or 3 years?

Right.

Two or 3 years. I'm not so sure right at the moment, given the fact that we still have good economics even with these differentials in the Midland Basin, I'm not sure I want to run up there and initiate a drilling program in Northern Gonzales, Southern Fayette, but it is something that we're considering, and we're watching the activity out there. So we're noncommittal at this point.

Our next question comes from the line of Jeff Grampp with Northland Capital.

Was curious maybe for Robert, you guys referenced some of the acreage trades that you're working on to get some longer laterals and maybe using kind of Slide 19 as a reference point to get a sense of materiality, maybe can you give us a sense or kind of ballpark us how that might change kind of the acreage or the inventory split between the various kind of lateral intervals that you guys point to?

That's a hard question to answer in that regard. What we will do is we'll end up with some 10,000 opportunity -- 10,000-foot opportunities that were previously 5,000 or 7,500s. And I don't have a ballpark number. But in one instance, we're working on that'll move 10 wells or so, maybe it's 8 wells from a 7,500 to a 10,000 footer. In another instance, it will move 5,000 foot laterals to 10,000 foot laterals where there hasn't been any drilling yet and that will really boost our economics. So I'm sorry, Jeff, I don't really have a number that I can quote you. Once we get these done, I'll be able to quote it.

Yes, but if you look at our current PowerPoint, what page is that, Robert?

19.

And you've been following us for some time. You'll see that we make slow but steady improvement in the number of longer laterals that we have. We're focused -- particularly now, we're focused on 10,000 foot laterals. But some of the economics that we're seeing in these shorter laterals still look very, very appealing. But the goal is to keep on working the land side to get more and more and more 10,000 footers.

All right, appreciate that. And then for my follow-up on that Lower Wolfcamp B well that you guys had that looks really strong here. Any -- I guess, I'm kind of curious if that was a surprise to you guys in a positive sense or if you had any indication internally on why that well performed so good here, if that was completion-related or it's just that -- that's a good resource that you guys are tapping into?

Well, Jeff, of course, we knew it's going to turn out like that. What do you want me to say? No, I'll tell you what, our guys geologically and completion-wise have done a great job on identifying what they think based on offset opportunities are wells that have been drilled and our own wells, and our log data of where to land these wells and then how to complete them. And we've just become probably better or more refined at where we're landing these wells. And sometimes mother nature cooperates and we get kind of results like this.

Jeff, I'm not going to give -- this is Frank. I'm not going to get my timing right here. But you'll recall maybe a year ago or so, that first 1,862 BOE a day well, I don't know when that one came on. But you recall that there was market skepticism about the value of the acreage in Southeast Reagan. And there were questions at that time before that came on and Robert and I said that we felt pretty good about that area. Our geoscience team both here and Midland felt pretty good about that area. And I for one, I'm hoping that we're going to see more 1,800 BOE, 2,000 BOE per day wells out there. So hats off to the geoscientists and the engineers for making that happen and overcoming some of the skepticism that existed about that acreage a year ago.

Totally agree.

It's not the short-winded, that's a long-winded way, Jeff, since I know you, of saying, "See, I told you so." So there you have it.

Our next question comes from the line of Joel Musante with Alliance Global Partners.

I just had a question on your type curves. Just -- they're very -- they're area-based. And I was just wondering as you develop more wells in different horizons, if it makes sense to differentiate that? And if there is a preference that's kind of emerging from your development program?

Joel, we've got internally probably 40 different type curves. And I'm just saving you a giant appendix to have to go through. So, I mean, that is true that we do have a massive amount of different type curves by area. And it gets refined over time as we drill our own wells and get knowing how our completions are going to -- how wells respond to our completion style. So this is just an easier way to present it, right, first of all. Second of all, in certain areas, certain horizons are working really well and in other areas a different horizons may be the money bench. And so we're focused on that early on when we have obligations and we're bouncing around. But as we get into development mode, we'll be drilling all the benches that make sense to drill at one time and some confined unit, let's call it, a number of wells and we're trying to figure that out right now, the best way to codevelop all these numbers of benches.

Our next question comes from the line of David Beard with Coker Palmer.

Just circling back to the question about price and differentials. I just wanted to push back a little bit in terms of why wouldn't you want to lock in some prices. Do you just want to maintain some flexibility for either the WTI to go higher or the differentials to narrow? Or what you're thinking when you look out into next year relative to those 2 items?

David, I'm not sure I completely understand your -- are you asking why we haven't hedged more? Or why we would layer on more hedges?

Yes, why wouldn't you hedge more given that you could receive the $60 net back on the $8 differential that seems to make a lot of sense. But maybe you just want to keep some flexibility if prices or differentials should move higher and narrow?

Sure, David. I'd say 2 things. One, we do continue to layer on hedges and really kind of anytime we bring on a batch of wells, we'll layer some hedges on. We've got the frac spread running as of last week on through well pad. And once those come on or around the time they come on, we'll revisit that and likely layer in some more hedges. The second thing is, we're hesitant to hedge beyond the PDP curve and we're really within sight of that based just on some limitations and the bank facility. And then just as a practical matter like having a good chunk of PDP hedged and really as we bring on more wells, we think about locking in some of the prices. But -- and I guess, kind of one of our points is, it does look attractive where you can kind of hedge net in the Midland Basin at around $60 in '19 and '20 and the differentials are pretty wide right now. And we're just going have to take the medicine on that. But we'll continue to layer in protection as we bring on wells.

Yes, I think Mark and Scott as well as our outside consultants are the experts on all of this. But I think it makes eminent sense that if you can hedge in some particularly the basis differentials for next year, that it's going to allow everybody to be able to forecast things a little bit better, including ourselves to support our capital program and so on. So yes, that's something that we will continue to consider.

(Operator Instructions) Our next question comes from the line of Jason Wangler with Imperial Capital.

Wanted to just ask on the M&A side or maybe even as you guys are working on the blocking and tackling of getting the acreage together in the Permian. Are you seeing anything open up whether it's drilling obligations like you guys are fulfilling but maybe others aren't or other things like that, that maybe would be opportunities longer-term for you?

So are you saying are other people not fulfilling their obligations and it creates an opportunity for us. Is that your question, Jason?

Yes, kind of, Robert. I mean, it sounds like you guys are kind of focused on that part of it to put yourself in a good position in the future when things presumably get better perhaps is there that would give you some optionality possibly to do some other things, I guess, with that (inaudible) kind of you're seeing that kind of start to happen and I'm sure it would be longer-term event but how you're seeing that maybe play out.

Yes. And we are actually seeing that where operators may have more opportunity than they can get to. And so there's an opportunity for us to come in and drill our way into acreage positions. Again, it's got to compete in inventory and it's got to make -- we got to make sure that we're fulfilling our other obligations, which we only got 4 or 5 next year, and then it dwindles down to 3 after that. So that's not the issue going forward. It's just balancing our other demands on our own acreage and what we want to do there. So those opportunities are there and that's a good place to stick a second rig if it buys our way into some more inventory that's accretive to what we already have.

Our next question comes from the line of Joe Allman with Robert W. Baird.

Just 2 questions here. So one, and I apologize if you covered this already because I got on late. In terms of rig number 2, what might change between now and year-end to prevent you from adding that second rig?

Well, my worst nightmare is why differentials in a falling commodity price environment, right? And there is a number of good analysts and other people on the phone right here and we're talking to the banks and nobody has got a really good crystal ball. So first and foremost as I indicated earlier, once you -- I've been working with the engineers and geologists all my life. Once you got the machine running, the first focus is do not lay down a rig or do not boot a frac crew if you got things working really well. So that's our first priority. This is not directly on point with your question but I'm leading up to the question. So we do have some inventory, where we have less than 100% working interest, we've done that in the past. Some of the other analyst know what we've just moved to keep the machine working, where we've moved to less than 100% locations and so forth. So that's number one. As we continue to build to -- so the second thing is, make sure we got a bank of time so that we can use bank days or we don't have to worry about losing any of our acreage on drilling obligations. Those are the first 2 things that we've done and I'll continue to do so. Then the second thing is take a look at where the prices are, bring in that second rig, avoid a long-term rig contract and take up a bit of a measured gamble, if you will, at the end of the year, at the beginning of the year to go drill 6 or 8 wells under a short-term 3- or 4-month or 10-well contract whatever we can do, but not lock that second rig on for a year until we have a clear line of sight to the take-away capacity. Now all of that said, if we had huge fears, if I had huge fears and I -- and Mark and Scott and Robert and I and the rest of our team debate this all the time. But the feel we're getting is that pipe and take-away capacity is going to be there sooner, rather than later. So as we move towards the end of the year, we will figure that all out and bring that second rig in on a short-term contract. Long-winded really mealy-mouthed way of answering you question and I apologize.

Joe, I might just add on to that from a perspective of what the second rig does and why you bring it on, it clearly, accelerates NPV to shareholders in cash flow and obviously, with our balance sheet having such low debt, we can do that and have a little bit of an outspend. And think it's a very good on a cash flow per share standpoint and still main very -- maintain very reasonable leverage. But you also know that we operate and think of things and we're measured in approach and don't get over our skis on anything. And we could have added the rig by now or we could do it right now. We're just measured and we want to make sure we're doing the right thing for kind of the bottom line and for shareholders. And the math looks fantastic. If you think about 2019 and '20 at kind of a net $60 price in the Midland Basin at the beginning of the year, when we're budgeting, thinking of $50, it still made a lot of sense from a math standpoint granted differentials were much lower at the beginning of the year. But it really is about doing the right thing at the right time that's going to deliver value to shareholders. And in the case of the second rig, we get some step change, improvements in efficiency is just kind of economies of scale, but also operationally. But we want to do it at the right time that it's clearly good for shareholders.

Just a follow-up. So when is the final decision point, probably not December 31. But like at what point you're going to make a decision, "Yes, we're going to sign a contract?" And you say it's going to be a short-term contract. What does short-term mean? Does that mean 3 months, 6 months?

Well, typically with your drilling contractors and particularly if some equipment capacities -- I mean there's times where you see really good hot rigs come available and there's times when they're not there. So I would anticipate that we would make a decision on a really good hot rig perhaps early in the third quarter, fourth quarter, I'm sorry. Early in the fourth quarter by November when that rig is coming off of a contract and get a good hot rig with good personnel and good equipment and a good contractor and get it ready to go starting in December. That would be kind of the plan right now. Robert, would you -- from an operational side, what do you think? Critique what I just said.

I think that's right. There's a couple of instances we're working on where it makes sense to have a 3- to 6-well kind of contract with a drilling contractor that if everything comes together be a perfect place to put it.

That's really helpful. And just one or 2 more if I could. So I know you talked about you're in the process of doing land trades. And I know what -- I know Jason asked a question about some other opportunities. But right now, are you working on some bigger deals besides those land trades? And just talk -- speak to the opportunity set besides what your answer to Jason's question.

Well, we're always working on bigger deals and what -- and ultimately, we will be successful just like we have on a smaller scale with Lynden and then a little bit bigger scale with Bold. We're always working on those. But as I hope you know and several of the other people know, we're pretty transparent on these things. What tends to get a little frustrating is you work on a deal, then you get a differential blowout and things slow up a little bit and the capital markets and so on. So I can tell you that we're not at a point where we're signing a PSA today or in the next week or so, but we're always working on those and we've had favorable response in terms of those kind of things. But it's -- hell, that crystal ball sometimes is even better and better from my view than differentials and take-away capacity, but it's influenced by things like that, so.

Okay, that's helpful. And just one real quick one on the future. So I know that the basis for Mark, basis is under $6, you said this or you could hedge at $6 for 2019 this morning. If I look at the futures market, I mean, you're below $6 starting from August through December next year. So are you -- is it much wider in the first half and much more narrow in the second half?

Yes, that's absolutely right.

So operator, I think that's about our time limit. We got anybody else? So that's it. Thank you to everybody for joining us on this call. And hopefully, you realize that we have a business under control, that we're efficient at what we're doing, that we care about our shareholders and that we have been through these drills in the past and have been successful. So thank you very much.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for participation, and have a wonderful day.