Ring Energy Inc (REI) 2018 Q2 法說會逐字稿

Greetings, and welcome to the Ring Energy 2018 Second Quarter and 6 Months Financial and Operating Results Conference Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Tim Rochford, Chairman of the Board of Directors. Thank you, sir. You may begin.

You bet. Thank you, operator. And we'd like to welcome all listeners to our second quarter and 6-month 2018 financial and operations conference call for Ring Energy.

Once again, I'm Tim Rochford, Chairman of the Board. Joining me on the call this morning is our CEO, Kelly Hoffman; our President, David Fowler; and of course, Randy Broaddrick, our CFO; and followed up by Danny Wilson, our Executive VP and Chief Operating Officer.

Today, we will cover the financials and operations of the second quarter and 6 months ended June 30. We will review all results, provide some insight and current progress as it relates to third quarter. At the conclusion of the review, we will open up for any questions that we might have as a follow-up.

So with that, I'm going to turn it over to Randy. And Randy, if you could give some review on the financials, please. Thank you.

Thank you, Tim. Before we begin, I would like to make a reference that any forward-looking statements, which may be made during this call, are within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued Wednesday, August 8. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com.

For the 3 months ended June 30, 2018, the company had oil and gas revenues of $29.9 million and net income of $4.7 million as compared to revenues of $14.5 million and net income of $1.9 million in the second quarter of '17. For the 6 months ended June 30, 2018, the company had oil and gas revenues of $59.8 million and net income of $10.4 million as compared to revenues of $26.7 million and net income of $3.2 million in 2017.

For the 3-month period 2018, the net income includes a pretax unrealized loss on hedges of approximately $1.1 million. For the 3-month period 2017, the net income includes an additional tax provision of $106,000. Without these items, net income would have been $5.6 million and $2 million for the 3-month periods 2018 and 2017, respectively. For the 6-month period 2018, the net income includes a pretax unrealized loss on hedges of $1.9 million and an additional tax provision of $1.2 million. For the 6-month period 2017, the net income includes an additional tax provision of $311,000. Without these items, net income would have been $13 million and $3.4 million for the 6-month periods 2018 and 2017, respectively. For the 3 months ended June 30, 2018, our oil price received was $61.70 per barrel, an increase of 36% from 2017. And our gas price received was $3.02 per MCF, a 6% decrease from 2017.

On a per BOE basis, the second quarter 2018 price received was $57.26, an increase of 33% from the 2017 price. For the 6 months ended June 30, 2018, our oil price received was $61.21 per barrel, an increase of 31% from 2017. And our gas price received was $3.24 per MCF, essentially flat as compared to 2017. On a per BOE basis, the 6-month period ended June 30, 2018, price received was $57.65, an increase of 31% from the 2017 price.

As noted in our press release, total lease operating expenses, including production taxes, for the 3 months ended June 30, 2018, were $15.44 per barrel of equivalent or BOE. Without production taxes, production costs per BOE were $12.70. This is compared to $12.44, including production taxes or $10.40 without production taxes in the second quarter of '17. For the 6 months ended June 30, 2018, total lease operating expenses, including production taxes were $14.72 per barrel -- per BOE. Without production taxes, production costs per BOE were $11.97. This is compared to $12.36, including production taxes or $10.26 without production taxes in the 6-month period of '17. The increase for the 3-month period 2018 when compared to more recent quarters is primarily about timing: timing in regards to when work was completed, either at the very end or very beginning of a quarter; timing in relation to completions, which affected production levels; and timing regarding production versus sales information.

Looking at the 6-month period 2018, it is in line with our approximate $12 per BOE estimate, excluding production taxes. Going forward, we anticipate our production cost per BOE, excluding production taxes, to be around that $12 range. Most production taxes are based on value of oil and gas sold. So our production tax expense is directly correlated to the commodity prices received. Our production taxes as a percentage of revenues remained relatively flat and should continue to be.

Our total depreciation, depletion and amortization or DD&A, including the accretion of our asset retirement obligation, per BOE increased for the 3 months ended June 30, 2018, to $17.81 per BOE as compared to $15.71 per BOE for the same period in '17. Our total DD&A per BOE increased for the 6 months ended June 30, 2018, to $17.32 per BOE as compared to $14.71 per BOE for the same period in 2017. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts.

As to total amounts, total DD&A increased approximately 75% for the 3 months period ended June 30, 2018 and approximately 101% for the 6-month period as compared to the same periods in 2017. These increases are a result of a combination of significantly higher production volumes and the increased depletion rate discussed above. Our overall general and administrative expense increased $785,000 for the 3 months ended June 30, 2018, as compared to the same period in 2017 and $1 million for the 6 months ended 2018 as compared to the same period in 2017. On a per BOE basis, this equates to a decrease from $7 in 2017 to $6.03 in 2018 for the 3-month periods and from $8.59 in 2017 to $6.01 in 2018 for the 6-month periods. The increases in total were primarily the result of increases in compensation expenses, including an increase in stock-based compensation of $190,000 for the 3-month period and $280,000 for the 6-month period as compared to the same periods in 2017.

On a diluted basis, the income per share for the 3 months ended June 30, 2018, was $0.08 as reported. Excluding the $1.1 million pretax unrealized loss on hedges and the $1 million noncash charge for share-based compensation, this becomes net income of $0.10. This is compared to income per share of $0.04 as reported or $0.05 per share excluding the $106,000 additional tax provision and $812,000 noncash charge for share-based compensation in 2017.

On a diluted basis, the income per share of the 6 months ended June 30, 2018, was $0.17 as reported. Excluding the $1.9 million pretax unrealized loss on hedges, the additional tax provision of $1.2 million and a $2.1 million noncash charge for share-based compensation, this becomes net income of $0.23. This is compared to income per share of $0.06 as reported or $0.09 per share excluding the $311,000 additional dollar -- additional tax provision and $1.8 million noncash charge for share-based compensation in 2017.

As of June 30, 2018, we had no amounts drawn on the $175 million borrowing base on our credit facility and had cash on hand of $13.4 million. Although we did not formally announce an increase to our capital expenditure budget, due to our successful development efforts -- results, we did expand upon our previously announced budget in the late first quarter and second quarter. Danny Wilson will address this further later in the call.

For the 3 months ended June 30, 2018, we had positive cash flows of approximately $17.3 million or $0.28 per diluted share compared to approximately $8.7 million or $0.17 per diluted share for the same period in 2017. For the 6 months ended June 30, 2018, we had positive cash flow of approximately $36.5 million or $0.61 per diluted share compared to approximately $15.8 million or $0.31 per diluted share for the same period in 2017.

With that, I will turn it back to Tim.

All right. Thank you, Randy. I appreciate that. I'm going to ask Kelly. Kelly, if you wouldn't mind, just give us some overview operational standpoint for the year so far.

Great. Thanks, Tim, and thanks, everyone, for joining us.

In the 3 months ended June 30, 2018, the company on its Central Basin Platform asset drilled 14 new horizontal San Andres wells, and we're in the process of drilling #15 and 1 in its North Gaines property at the end of the quarter. All the wells drilled in the second quarter were 1-mile long. In the second quarter, the company finished testing and filed initial potentials on 18 new horizontal wells, 2 wells which were drilled in the third quarter of 2017, 3 which were drilled in the fourth quarter of 2017 and 7 which were drilled in the first quarter of 2018 and 6 which were drilled in the second quarter of 2018.

The average IP on the 18 wells tested in the second quarter 2018 was approximately 440 barrel of oil equivalents per day or 103 BOE per 1,000 feet. This compares to 12 horizontal wells, which the company finished testing in the first quarter of 2018 and had averages of 436 BOE per day and 102 barrel of oil equivalent per 1,000 feet. In addition, the company had 14 new horizontal wells or San Andres wells, which were in varying stages of completion and testing as of June 30, 2018.

Now for the 6 months ended June 30, the company drilled 24 new horizontal San Andres wells on the Central Basin Platform asset. In addition, the company drilled one new horizontal well in the North Gaines property and one new horizontal Brushy well, Brushy Canyon well that is, on our Delaware property asset. And we also had 3 saltwater disposal wells we drilled during that time too. And in the first 6 months of 2018, the company tested and filed IPs on 30 new horizontal wells. And the average IP of the 30 wells was 438 barrels of oil equivalent per day or 103 BOE per 1,000 feet.

I know that there's been a lot of discussion around the additional CapEx. Danny's going to give us a lot of color on that, Randy mentioned a moment ago. Just as a high line, and then Danny is going to get in the weeds pretty deep here and give you some more color on. But just at the top level, about 1/3 of that was for infrastructure and about 2/3 was for R&D, our version of R&D, and we'll explain that in a little bit further.

Just a quick recap on the Gaines asset. We drilled 2 vertical test wells, and we've since drilled 3 horizontal wells, the first of which was one that we reported in ops report being a test well that we've done a lot of work on. It gives a lot of meaningful information. You're going to hear a lot more color about that. We're very excited about what we're going to say. And then we also did the same thing in the Brushy Canyon, drilled one well out there so far and really like what we're seeing.

But I'm going to leave that for Danny to talk about. I don't want to steal his thunder. But anyway, Danny, if you want to update everyone on some further information in operations, take it away.

Sure, sure. Thanks, Kelly. And I appreciate the opportunity to bring everybody up to speed on our operations.

One thing I want to address right off the top was the takeaway issue. Obviously, this is a very hot topic in the industry right now. I just want to assure everybody that we are in constant contact with our purchasers and our pipelines and with our brokers who help us with that process. And we have been assured that because of our relationship between Centurion, Oxy and ourselves that we are in the best possible position we could be in as far as takeaway goes. As you know, Oxy and Centurion are sister companies. Oxy has firm transportation on Centurion pipeline, which a bulk of our production goes into. And by being a virtue of those mean the customer walks in, we therefore have then extended that firm transportation. Again, we're in constant contact with them and we have been assured that we have, in the foreseeable future, no issues as far as takeaway goes.

Another question that has come up was the fact that our -- we're showing a little gassier production for this quarter than we have in the past. If you'll recall, back at the end -- at our first quarter call, we mentioned that we had just finished commissioning our Central Basin Platform gas pipeline, which allowed us to start selling gas, which had previously been flared and which we were receiving no income for that at the time. So what you're seeing as far as the gassier production, that's strictly to do with us now having that line open, selling gas to DCP. And by result, we're now receiving cash and income from that production, which was just being flared previously. The wells are not getting gassier. We still anticipate that we're going to be in that 90% range on oil cut moving forward.

As far as the CapEx goes. I want to assure everybody that we have not had any appreciable increases in our drilling cost. I know that was one of the questions everybody had. We are still holding the line on those costs. We still feel like we are drilling the wells for $2.2 million for the 1 mile and $2.6 million for 1.5 miles. We also -- during this quarter, one of the things that was unbudgeted that we started out the quarter with was we noticed some of the early -- our older wells were starting to have some abnormal decline rate as they got a little bit older. And we, on further investigation, found that we were having some iron sulfide buildup in those wells. We initiated a program to go in and start cleaning those wellbores out, and we've mentioned this in the previous call. But we started cleaning those wellbores out, going in and pinpoint – doing pinpoint asset jobs across the perforations. The wells are responding very positive. For the most part, they are all coming back above the original decline curve. So we're seeing very positive results from that, and we're just very encouraged. And we did about 9 of those wells during the quarter. Those jobs were around $300,000 to $400,000 apiece. That was unbudgeted. And so that was a bit of a cost overrun for the quarter. The -- and not that it was an overrun. It was something that had to be done.

And Kelly mentioned that part of the expense that we went through was infrastructure costs that were anticipated. And we went through -- we took advantage while we were out drilling our Brushy Canyon well in the Delaware to drill an extra disposal well. We stopped on the way back after we drilled the Brushy Canyon well. The rig was there. We said, hey, let's go ahead and drill another disposal well while we're there. We have 11 more permitted in the area. And with that well, we'll just grab one of those while we can. We went ahead and did that. Of course, we had the associated cost of electrical flow lines, right of ways, battery equipment that goes along with that, that was not in the original budget. We also built out an extension to our core area on the -- on our oil, gas and water systems. We were able to secure some leases to the south of our existing acreage, about 6 miles south. We have subsequently gone in and drilled 3 wells in that area. Highly successful, very productive wells. We took advantage of that to go ahead and build out our system in anticipation that we'll be picking up more acreage down in that area. So that was an additional cost that we had not anticipated. So that was the bulk of the infrastructure issues that we had to deal with in addition to that.

Now I'll move right on into our Brushy Canyon test out in the Delaware, because that in itself was some of the issue with infrastructure. That well is our first horizontal Brushy Canyon well. We drilled several size wells in the past, took cores, and did all the work we needed to, to look at those and decided that we had a very productive reservoir there that we were just sitting on. The acreage is HBP. We were under no pressure to drill the wells, but we were highly excited about with the potential results of that.

We did drill our first well. It's a very high up on structure. It's probably about as high on structure as we can get in our area, the thought being that we will corner post our acreage. We'll drill one kind of across the acreage and try to delineate what it looks like moving forward. The first well did come in a little gassier than we anticipated. It came in, I think we previously announced, at 2.8 million cubic feet a day and about 130 barrels of oil. 60 days later, we're still holding that production volume.

We had some people ask what does the decline rate and the curve look like. Right now, I don't have the decline rate to give you, because it's not declining. We still have a very high fluid level in the well. I'm excited to see what happens as we continue to pump the well down. That being said, when I referred to the infrastructure issues, that well came in much stronger than we had anticipated. It causes to have to beef up the equipment out there considerably. We had to go to high-pressure flow lines, high-pressure vessels, which we had not anticipated. It caused us to spend some extra money that we had not anticipated moving forward.

In the future, one of things we're working on now, that well, we don't have capacity in our current gas system to put that well on sale for the gas. And so we're looking at probably sometime in the early fourth quarter, having a high-pressure system built out to accommodate that well and hopefully additional wells we'll be drilling. We haven't really discussed. We've internally discussed on timing on that. I would suspect maybe we'll drill one more well by the end of the year. But the development plan has not been put in place. I wouldn't anticipate that to happen till probably sometime in 2019.

Moving on, I know one of the big things everybody is very excited about and wants to hear about is our North Gaines project. As Kelly mentioned, we've drilled several vertical science wells over the last 1.5 years with very encouraging results. We're drilling in an area where it's fairly devoid of San Andres production. We did a lot of science work. We saw some things in the core work that we did, the logs that we did that were very encouraging to us. We went in and drilled our first well, which we talked about in previous calls. We had not completely finished that well when we had our last call. But we used that well -- we used the sleeve system in that so that we could go in and open and close sleeves and test various different completion techniques in one wellbore rather than drilling a well and then trying one technique and drilling another and trying another technique. We decided to save the cost of multiple wells and use the sleeve technique.

We tried 3 different -- actually 4 different techniques within that -- in that wellbore in 3 different segments. Starting now, we're just asked to see how that would do and then doing various size frac jobs to see how the well went. Very encouraged by the results. We -- between each one of those, we put the well on test, which requires us obviously to get a pulling unit there, a pump, coiled tubing, various things and -- but going through that careful technique of trying different things, it was a very expensive process. However, we learned a great deal during that -- while we were doing that work. And so what we did then is we -- next we moved over and drilled a well next to that one. We did put that well on production that came in around 130 barrels a day. It's slightly less than that now, even though we feel like the effective wellbore that's open is very limited due to the different techniques that were used in that well. We did move over, drilled our second horizontal well, again, using the sleeve technique. And we're moving forward with that, but we're also investigating how to get back to our plug and perf frac, which we use in our core area.

So we drilled the second well. We did the -- did one frac all the way through. I mean, not one, but one technique all the way through, 44 different sleeves and put the well on production about 2 weeks ago. And so far, we're very encouraged by the results. Over the last few days -- the production continues to rise. But over the last few days, it's been making in excess of 400 barrels of oil a day. This is again in an area that was fairly devoid of San Andres production in the past. So we're very encouraged by that. It is making some gas, probably around 100 Mcf a day. But for the most part, it's a very oily area. We did then move on from that well and moved 5 miles to the southwest, and we have drilled our third horizontal well, second producer in our third horizontal, again, using the sleeve technique type completion and just finished the frac job on that well day before yesterday. Obviously, we haven't -- we've to go in and clean it out and then open it for flow. I will say we did do a science well in that area prior to a vertical science well prior to drilling the horizontal, the cores logs. They look as good or better than the first area. So we're very encouraged to see what this well does.

We -- during our call earlier in the quarter, we did talk about how we had some operational glitches early in the process due to different various reasons we don't need to go back into again. But I just want to assure everybody that we have those issues worked out. They will not occur again. We are moving forward. We were back on track as far as our growth goes at the end of this -- of the last quarter. And we're continuing that into this quarter. And I think you'll see us get back to our previous growth moving forward. And we're -- I think we're going to be very -- you're going to be very pleased as we go forward with these projects, especially now that we have opened up new frontiers with the Brushy and the North Gaines.

And with that, I'm going to turn it over to David.

Thank you, Danny, appreciate that. Thanks for that update. For the most part, it's business as usual. On the leasing and the acquisition front, we continue to add to our lease totals in our core area.

On a positive note, we continue to see an increase in cooperation with the companies that have been reluctant in the past to lead, to participate with their minerals or in some cases the HBP acreage and are now more agreeable to do so. And as a result, we're seeing success in leasing some really quality offset acreage in our core area and on the platform. And we continue to make progress of increasing our net gross as well.

Over the past several months, we've seen several excellent acquisition opportunities that would be a great fit to our existing asset base. And we continue to have a dialogue with some of those management teams. And to that end and as you all are very well aware of, we have ample liquidity that gives us the financial flexibility to move quickly and decisively when we come to terms on the accretive transaction that will have a positive impact on our shareholder value.

And with that, I'll turn it back to Tim for closing comments.

Okay. Thank you, David. Thank you, everyone. Well, this really actually concludes the operational review. I know everyone is anxious to get to the Q&A. So with that, I'm going to turn it back over to our operator. And operator, if you will open it up for question, please?

(Operator Instructions) Our first question is coming from the line of Neal Dingmann with SunTrust.

Tim, I don't know if you want to throw this to Kelly or Danny as far as, it definitely is noticeable, the big improvement in production that Kelly said on the press release and his prepared remarks, where you were at the end of June. Could you talk about kind of -- is that the trajectory we should continue to think through the rest of the year? Or maybe I know without sort of formal guidance, maybe just to give us an idea of -- there certainly was a noticeable increase. And just maybe just talk about the production, Kelly, if you could a bit.

Absolutely, Neal. Listen, I -- look, as Danny just touched on briefly and not to saw sawdust, but just touched briefly with our last call, which was about midway through our second quarter, we did get off to a slow start. But we want to reassure we want to -- those are items are going to be corrected. Danny is just underlining that those areas have been corrected. And as everyone on this call knows, we finished the second quarter, the month of June very strong and entered into the third quarter aggressively on all levels of from the growth standpoint. But I think to Kelly's remarks in the release, but maybe more importantly, let's just let Danny take a little more color -- shed a little bit more color on that. Danny, as we're going in the third quarter for production.

Yes, you bet. No, obviously, we -- as we had said, we had some operational issues with the frac crew being delayed. We let it go. And we were delayed in getting it back due to some issues that happened. They were out of our control. We have put in place with Schlumberger, as obviously everybody knows, is our frac company that we use, they are aware that if there are any operational issues moving forward with another operator who is borrowing the crew that they're going to rig down and move off and come back to us rather than wait there for an extended period of time for issues to be resolved. And that's kind of what got us in that bind earlier, which put us behind on fracking and which obviously -- it kicks everything down the line, because you've got to clean the frac, you clean it out, hang it on, test it. And it just kind of moves everything down. We have not had any kind of issue like that since that point. We are back on our traditional growth rate. And I think you'll see that as we move into this quarter.

Very good. And then just one follow-up as far as the new areas, certainly the newer areas, I should say, as far as North Gaines and Brushy's, both sound very encouraging. Given sort of the need for free infrastructure there, what -- timing-wise, if you could address each? When might we see a bit more activity in those areas, including the potential first production coming on?

I'm sorry, excuse me. Did somebody else say something?

No, I was going to say something. Tim, but you go ahead.

No, no. Danny, look, I'll turn right back to you. What I was going to say is that was a very good question. And what we're planning on doing internally is with the recent success, particularly with the results that Danny just reviewed here in Northern Gaines and with what's going on at the Brushy, we were huddling up and we've been huddling up internally. And so a revised plan for the remainder of the year will be really -- we'll be getting into that here very soon and will be adopted. And when that decision has been made -- and we hate these moving targets, okay? But gosh, we're growing. Things happen so rapidly here, it's tough to tie it down. So we want to really be certain. We want to be comfortable with it. But as soon as we tie down some of those moving targets, we're going to come formally back to the Street with an amended CapEx for the year, balance of the year. But go ahead, Danny, and add to that please.

Yes. No, just in the short term, Neal, one of the things we're working on right now, we're in the planning and design process as well as securing of right of way in equipment on the Brushy Canyon area. And that's because we have an existing system in place, but it's for our low-pressure vertical well. If we were to try to put that Brushy well in there with those, we would just knock all the other leases offline, which would not only shut down the gas, but would back up the system and adversely hurt our oil production too. So we are in the process of building out and designing that. It's not a big project. It will be a couple of million dollars to do that. And we anticipate that -- we're shooting to have that online early fourth quarter. Once that's in place, then that'll free up some space for us to be able to go out and do some -- maybe do some additional testing in the area. As I mentioned, our plan is to kind of corner post the production our acreage, kind of see what it looks like across there. We think that maybe as we move down dip and maybe to the north, hopefully, we'll see a little more -- a little oilier test over in that area. But and we've secured additional space on Anadarko who we – or it's Delaware Basin midstream, but it's owned by Anadarko. And we secured -- already secured additional space in their system to accommodate this Brushy gas. As for North Gaines. I think the next thing on our list is to drill a disposal well. One thing I neglected to say in my earlier comments was one thing we're very excited about in this area is that we're seeing a much higher oil cut in these wells than we are to the south in our core area. Down there, we typically see 10% to 15% oil cut. And up in this North Gaines area, the initial test well that we worked on, we're seeing oil cuts anywhere from 25% all the way up to -- we were seeing towards the end that it was pumping down 40% of oil cut. The second well, the one that's the first real true producer already has oil cuts of 25%, 26%. So we're very excited about that, makes much less water. But we still need a disposal well. We don't want have to haul all this water. And drilling the disposal well probably maybe this quarter, at the very least -- at the very latest probably next quarter, we'll get that online and that'll free us up to move back up in that area. We've got a lot of acreage that we're very excited about up there. It'll kind of grow like it did in our core area. You'll see us build the infrastructure out. So you'll probably see our drilling kind of concentrated in that kind of an area because of the infrastructure. And then we'll build out from there. But this second well -- second producer comes in, likely hope, it's going to prove up a substantial amount of acreage, being that it's 5 miles away. But that's kind of the infrastructure -- the major infrastructure things I see as far as North Gaines and Brushy moving forward.

And Neal, just as a follow-up so that everybody clearly understands. Once we have a handle on that -- and as you can see, there's a few moving parts, all positive. But once we have a handle on that, we will evaluate and will come back to the Street with an amended CapEx so that the folks are going to know well in advance what we can anticipate from the spend.

The next question is coming from the line of Jason Wangler with Imperial Capital.

Wanted to maybe dovetail a bit on what you're talking on the infrastructure side. In terms of timings on those things, obviously you're working through the cost. But is that a few months' time frame to kind of get ready before you'd be able to go out and start drilling more actively? Or how should we think about it from a timing of development standpoint on the assets?

Danny?

That's -- as far as timing goes, obviously, we're going to continue drilling our core area while we're doing all this other work in preparation. So we won't to be shut down while we're doing the infrastructure. I just want to point that out. As Tim mentioned, we're going to sit down fairly soon and will work out and formalize this CapEx. But I do think you'll probably see the disposal well in North Gaines with the associated build out of the flow lines and such -- and electrical as we start out that area. But – and then so I don't anticipate getting into that big drilling program probably until next year sometime. We may do some additional work in the area. It's not going to be -- we're not going to move clearly up there full time and just get busy right away. And kind of same on the Brushy. We'll give it some time to get digested and then do our planning as we move forward to how we're going to get the gas into the market and then drill our additional wells.

Okay. So is it fair to kind of think of it as kind of a couple things coming together in 2019 where you kind of really have a more formalized plan both for North Gaines and Brushy and that you have the infrastructure laid out, you have some well data, things like that?

I think that's fair to say, yes.

Okay. And then just in the core Central Basin, it seems like the wells are still doing quite well. And just was curious, because of the infrastructure discussion -- I know you've talked in the past, but having a pretty significant amount of infrastructure there. Is there any concern about having to do more there? Or are you pretty happy with what you have and you'll be set up for some time?

No. I think we've done a very good job of probably building out that area. We have a few things to do. As I mentioned, we have a new area to the south that we've kind of opened up. It's doing very well. And it's -- that was kind of a pleasant surprise for us, how well those wells were doing down there, and we're working to expand our acreage position. And we -- but as far as any more anticipated growth in that area, I don't see much. Maybe 1 more additional disposal somewhere along the way.

The next question is coming from the line of John White with Roth Capital.

Danny just answered my question. I was going to ask about the oil cuts at North Gaines. And that is -- that information -- those are really nice oil cut numbers. That's -- I bet you're very, very pleased with that.

Thank you very much. It was a nice surprise.

Yes, it'll be lower LOE for you. So I do have another question. North Gaines, where is that structurally related to your core properties? Is it downdip, is that right?

Yes. It is downdip. It is -- those wells are around 6,000 feet deep as opposed to 4,600 to 4,900 feet in our core area.

I appreciate that. And on Brushy Canyon, Danny, I bet the high-pressure gas is a problem you don't mind having, right?

Well, I'd rather have oil, but I'll take high-pressure gas, yes.

High-pressure gas versus low-pressure gas, right?

Well, or no gas, yes.

The next question is coming for the line of John Aschenbeck with Seaport Global Securities.

For my first one, I kind of wanted to expand upon the acreage additions that I think was either Danny or David mentioned picked up some acreage here recently to the south and looks like you've also drilled a few more wells there as well. Sorry if I missed it, but how much acreage did you have there?

We didn't say. But John, let me just add that as you know, Andrews is a very old oil-producing county and it was fairly easy early on to gather up some acreage. It's become obviously more difficult. But you've got a lot of majors in there. And at this point, when we can add 160 or 320 or even 640, that's pretty -- that's a big chunk. Those are harder to come by, oftentimes are held by production by an existing operator. And of course, we've been observed. But people are liking what they're seeing. And as a result, their confidence has grown. And through that confidence, it's making it easier for us to be able to acquire some additional acreage and to develop areas that are close to core areas that we really like. So these are offset leases to those areas. And so yes, we're encouraged by the fact that those doors are opening up and we're able to secure some of those chunks of acreage as bolt-on.

Okay, got it. It sounds like to me maybe that the process is ongoing. So I understand if you can elaborate too much, but...

Yes, it is. Yes, it is.

So on that point, when should we expect an update from you guys there? And maybe just kind of put it all together and let us know how much acreage you've aggregated.

Yes, let me address that, John, if I may. This is Tim. So that is probably something that could parallel when we come back to the Street with something more formalized as it relates to the balance of the budget. CapEx-wise, the remainder of the year, we should be able to do an update on that -- give an update on that.

Okay, great. That leads perfectly to my next one. So Kelly, your prepared remarks and the press release this year recently spoke to the acquisition environment in the Central Basin Platform. The company has also -- you've expanded your borrowing base. Just seems like you're getting pretty close to a potential acquisition. Looks like the comments we just had, you had some stuff in the works too. And again, I understand you can't comment too much. But, I guess, twofold question. First, would you be willing to lean into your borrowing base if you did find a deal to fund that deal? And then secondly, if you do pull the trigger on a bigger deal, should we expect acceleration to follow?

Thanks, John. Yes, it's a good question. We've always looked at the borrowing base as a bridge, if you will, of course. And so -- and depending on the type of transaction, a lot of discussions I may have mentioned on the last call we had in the first quarter. And I know we have talked about this between us. We continue to be encouraged by the discussions that we're having with people, discussions that I think are better set expectations. And in those discussions, there's a lot of discussion that's around different type of structure. And obviously, some of those structures are debt, equity and all different kinds of things. So we're interested in pursuing these ideas. I don't have anything I could report to you today, of course. But we are seeing a lot more of those types of ideas surface. And some of them are large in nature and some of them are middle and some are smaller, but they're all very exciting to us. So I think we'll get something done, I'm very hopeful that we will without question. And I think that answered both ends of your question there. If I missed part of it, please restate it for me.

John, let me add to...

Go ahead.

So just -- I think just to add a little bit maybe more color to that as it relates to -- while we're getting closer. You know as well and most people on this call know as well enough that we're not proactive when it comes to debt. So we use it when we think it's a great tool, and we're going to continue to look at it just that way. But when you see us maneuvering and you see our base changing from $60 million to $175 million and you see us talk more and more about the opportunities, you can kind of sense, as you've already pointed out, that we may be getting closer to something. So I think your instincts are spot on. Whether or not -- like Kelly says, whether or not this comes to pass on some areas that we've been working very diligently on, only time will tell and remains to be seen. The other part of your question, I believe, was would that in itself trigger acceleration. I think that is a very good question. But it also has to be considered with the development opportunity and with the success that we're seeing in North Gaines, not to mention Delaware with the Brushy, that you have to kind of configure all those together and sit down and really plot that out. So keep that in mind if something like that happens in the near future from an acquisition standpoint, all of those factors will be considered together.

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

I apologize if you've already addressed this. But I just want to get a sense for how you're looking at Northern Gaines and in the light of differentials, are you deterred at all by -- from adding another rig there? Or are you more likely to kind of move rigs around and drill a few more wells there? Or kind of -- and I guess, infrastructure probably plays into that as well. So if you can just address that.

Well, it's a very good question, Joel, and it's a very good point to even spend more time on. Again, there's some moving parts here. There's more than just a couple avenues here to really drill down on. So I'll let Danny respond -- or at least ask Danny respond to that as it relates to the infrastructure, the takeaway issues, et cetera. But there's no question that for the first time for the company, Joel, we have now multiple areas not just to the research and development and while we're developing in our core area. But now we have multiple fronts that are going to justify the development. So you can see there's going to be a lot of planning, a lot of work that's going to go into those here over the next number of weeks and months. And as Danny pointed out earlier, probably through the most this year. But maybe, Danny, if you could expand on the takeaway side of that, of Joel's question as well.

Yes. And Joel, we've already started discussions with several companies in North Gaines on both takeaway for oil and gas. That was just in the preliminary stages right now. But we are actively out there looking for pipeline connections. We're talking to midstream companies about whether or not we want to let a midstream company build to us. Or do like we did to the south in our core area, just build out our own system and not pay that cost for somebody else to do it for us. So all very preliminary, but all things we're working on.

Our next question is coming from the line of David Beard with Coker & Palmer.

My question is a little bit around spending near term and long term. First, just near term, it seems the variability in the quarter is sort of $30 million in infrastructure. Are we looking at that kind of swing in the back half of the year? Or is a bulk of that spending behind us?

Good question, David. I think the bulk of that is behind us, with the exception of what we will be coming back to the Street, like I said, in a number of weeks and we'll formalize that. But I think Kelly can touch on that, because I know that he and Danny have been working hard on this. So maybe, Kelly, you could drill down a little bit for us on that, please?

Thanks, David. Good question. Our plans right now are -- we may add a disposal well here and there where we think is necessary as these things continue to expand. As Danny mentioned, we'll be up in Gaines a few more times potentially this year. And in doing so, as he mentioned on both the takeaway side, we're having discussions with a lot of different people. We're doing the same thing on the disposal side. We've set some things in motion already as it relates to disposal costs. We'll keep those costs way down on a per barrel basis. The electrical side is in motion, as we speak, too. So we'll have a little bit of spend, but it won't be anywhere near that. And at the end of the day, if we -- with what we have learned so far in Gaines on the drilling side, the tweaking that we're doing going forward, the real heavy lifting of all of that, I feel like, was done in the first horizontal test well and those 2 verticals. We don't have the need in that immediate area. I say immediate area, although it's a pretty large size area, about a 5-mile radius, so. But in that area, we don't have the need to repeat that. We are going to be continuing to tweak a few things here and there, but they'll all be minor by comparison.

Good, that's helpful. And bigger picture, if you work through the rest of this year and '19 in both Gaines and in Brushy Canyon, when you look out to 2020, could each of those areas take a dedicated rig? And would you want to do that if everything was lined up from infrastructure and locations and acres?

David, this is Tim. So you're absolutely right about that, and that was kind of to my earlier point here a few moments ago is that we have multiple fronts now. So as we wrap up the second half of '19 and particularly as we're getting closer to 2020, I think that's very reasonable to believe that, that could happen.

There are no additional questions at this time. So I'd like to pass the floor back over to Mr. Rochford for any additional concluding comments.

Okay. Thank you, operator. I appreciate that. And listen, we want to thank everybody. We know it's a busy time and lots of things to do. As always, we have an open door policy. So if you have follow-up information, feel free to reach out to Bill Parsons, Investor Relations, or to any of us at the company. And have a wonderful day, and thank you.

Ladies and gentlemen, this does conclude today's teleconference. We thank you for your participation, and you may disconnect your lines at this time.