Ring Energy, Inc.
Q2 2018 Earnings Call Transcript

Published: 9 Aug 2018

[Operator:]

Greetings, and welcome to the Ring Energy 2018 Second Quarter and Six 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.

[Tim Rochford:]

You bet. Thank you, operator, and we would like to welcome all the listeners to our second quarter and six months 2018 financial and operations conference call for Ring Energy. Once again, I am 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 by Danny Wilson our Executive VP and Chief Operations Officer. Today, we will cover the financials and operations of the second quarter and six months ended June 30th. We will review our results provide some insight and current progress as it relates to the third quarter. At the conclusion of the review, we will open up the call for any questions that we might have as a follow-up. So with that, I am going to turn it over to Randy, and Randy, can you give us some review on the financials, please. Thank you.

[Randy Broaddrick:]

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 9. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com. For the three months ended June 30, 2018, the company had oil and gas revenues of $29.9 million and a 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 2017. For the six months ended June 30, 2018, the company had oil and gas revenue 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. The three months period 2018, the net income included a pretax unrealized loss on hedges of approximately $1.1 million. For the three months ended period of 2017 the net incomes include an additional tax provision of $106,000. Without these items, net income would have been $5.6 million and $2 million for the three month period 2018 and 2017 respectively. For the six months period 2018, the net incomes includes a pretax unrealized loss on hedges of $1.9 million and an additional tax provision of $1.2 million for the six months 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 six months period 2018 and 2017 respectively. For the three 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 six 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 six-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 three months ended June 30, 2018 were $15.44 per barrel of equipment to BOE without production taxes, production cost 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 2017. For the six months ended June 30, 2018, total lease operating expenses including production taxes were $14.72 per BOE, without production taxes production cost per BOE were $11.97. This is compared to $12.36 including production taxes or $10.26 without production taxes in the six-month period of 2017. The increase for the three-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 completion which affected production levels and timing regarding production versus sales information. Looking at the six-month period 2018, it is in line with our approximate $12 per BOE estimate excluding production taxes. Going forward, we anticipate our production costs per BOE excluding production taxes to be around that $12 range. Most production taxes are based on values, oil and gas sold; their production tax expenses are 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 three months ended June 30, 2018 to $17.81 per BOE as compared to $15.71 per BOE for the same period in 2017. Our total DD&A per BOE increased for the six 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 three-month period ended June 30, 2018 and approximately 101% for the six-month period as compared to the same period 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 to $785,000 for the three-month ended June 30, 2018, as compared to the same period in 2017, and $1 million for the six 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 three-month period, and from $8.59 in 2017 to $6.01 in 2018 for the six-month period. 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 three-month period and $280,000 for the six-month period as compared to the same period in 2017. On a diluted basis, the income per share for the three months ended June 30, 2018 was $0.08 as reported. Excluding the $1.1 million pretax unrealized loss on hedges and $1 million non-cash charge for share-based compensation this becomes a 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 non-cash charge for share-based compensation in 2017. On a diluted basis, the income per share for the six 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 non-cash 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 dollars-- additional tax provision and $1.8 million non-cash charge for share-based compensation in 2017. As of June 30, 2018, we had no amounts drawn on the $175 million borrowing based on our credibility 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 effort-- 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 three 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 six months ended June 30, 2018, we had positive cash flow of approximately $36.5 million $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.

[Tim Rochford:]

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

[Kelly Hoffman:]

Great. Thanks, Tim and thanks everyone for joining us in the three months ended June 30, 2018 the company on the Central Basin Platform asset drilled 14 new horizontal San Andres and we are in the process of drilling number 15, and one in its North Gaines Property at the end of the quarter. All the wells drilled in the quarter were one mile long. In the second quarter, the company finished testing and filed initial potentials on 18 new horizontal wells; two wells which were drilled in the third quarter of 2017, three which were drilled in the fourth quarter of 2017 and seven which were drilled in the first quarter of 2018 and six 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 thousand 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 a 102 Barrel of Oil Equivalent per thousand 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 six months ended June 30th, 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 three saltwater disposal wells we drilled during the time too, and in the first six months of 2018 the company tested and files 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 thousand feet. I know that there's been a lot of discussion around the additional CapEx, Danny is 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 there, so it's pretty deep here and give you some more color on, but just at the top level about a third of that was infrastructure and about two-thirds was for R&D, our version of R&D and will explain that a little bit further. Just a quick recap on the Gaines asset. We drilled two vertical test wells and we've since drilled three horizontal wells, the first of which was one that we reported on-- ops report being a test well 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. That's going to be 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 I would really like what we're seeing, but I am going to-- I am going to leave that for Danny to talk about, don't want to steal his thunder but anyway. Danny, if you want to update everyone onto further information and operations, take it away.

[Daniel Wilson:]

Sure, sure, thanks, Kelly. And I appreciate the opportunity to bring everybody up to speed on our operation. One thing I wanted 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're 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 bulk of our production goes into, and by being a virtue of us being a customer of Oxy, we therefore have been extended firm transportation. Again, we are in constant contact with them and we'd have been assured that we have in the foreseeable future no issues as far as takeaway go. Another question that has come up was the fact that we show a little gassier production for this quarter than we have in the past. If you will recall, back at the end of - in our first quarter call, we mentioned that we had just finished and commissioning our Central Basin platform gas pipeline, which allowed us to start selling gas which had previously been flared, and, of course we were receiving no income for that at the time. So what you are seeing as far as the gas year production is strictly to do with us now having that line open, selling gas to DCP and by result, we are now receiving cash and income from that production which was just being flared previously. The wells are not getting gas here; we're still anticipate that we're going to be in that at 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 increase in our drilling costs. 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 one mile and 2.6 for the mile and a half. We also, during this quarter, one of the things that was unbudgeted that we-- that we started out the quarter with, was we noticed some of the early-- our older wells are starting to have some abnormal decline rate as they got a little bit older. And we on further investigation found that we are 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 and going in pinpoint-- doing pinpoint acid jobs across the perforations and the wells are responding very positive. For the most part, they're all coming back above the original decline curve. So we are seeing very positive results from that, and we are just very encouraged and we did about nine of those wells during the quarter, those jobs run $300,000 to $400,000 a piece. That was unbudgeted and so that was a bit of the cost overrun for the quarter. 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 unanticipated. 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 build the Brushy Canyon well-- the rig was there. We said, hey, let's go ahead and drill another disposal well while we are in there. We had 11 more committed in the area and we thought, well, we'll just grab one of those while we can. We went ahead and did that. Of course, we had the associated costs of electrical flow lines right-of-way, 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 six miles south. We have subsequently gone in and drilled three 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 will 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 was our first horizontal Brushy Canyon well; we drilled several size wells in the past to cores, did all the work we needed to look at those and decided that we had a very productive reservoir there that we were just sitting on. Acreage is HBP; we were under no pressure to drill the wells, but we were highly excited about what the potential result of that. We did drill our first well; it's a very high upon structure. It's probably about as high on structures we can get in our area, the thought being that we will-- corner post our acreage we will drill one kind of across the acreage and try to delineate what it looks like moving forward. The first level they come in a little gassier than we anticipated; it came in and I think we previously announced a 2.8 million cubic feet a day and about 130 barrels of oil. 60 days later, we are still holding that production volume. We had some people ask what the decline rate is and what the curve looks like right now? Well, I don't have a decline rate to give you because it's not declining. We still have a very high fluid level in the well. I am 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 caused us to have to beef up the equipment out there considerably. We had to go to a high pressure flow lines, high pressure vessels which we had not anticipated-- it cost us, cost us just to spend some extra money that we had not anticipated moving forward. In the future one of the things that we are 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 are 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 will be drilling. We haven't really discussed; we've internally discussed some timing on that. I would suspect maybe we will 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's very excited about and most hear about is our North Gaines project. As Kelly mentioned, we've drilled several vertical size wells over the last year and a half with very encouraging results. We are drilling in an area where it's fairly devoid of San Andres production. We did a lot of size work. We saw some things in the-- in the core works 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 a sleeve system in that, so that we could go in and open and close sleeves and test various different completion techniques in one wellbore as in drilling, you know 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 three different-- actually four different techniques within that --in that wellbore in three different segments. Starting out with just asset to see how that would do, and then and then doing various sized frac jobs to see how the well went. Very encouraged by the results, we, you know, between each one of those we put the well on test, which requires obviously to get own unit there, a pump, coal tubing, various things and by going through that careful technique of trying different things, it was a very expensive process. However, we learned a great deal doing 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 we used in that well. We didn't move over, drilled our second horizontal well. Again using the sleeve technique and, will-- and we're moving forward with that, but we're also investigating how to get back to our plug-in 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 two 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 Anders production in the past, so we are very encouraged by that. It is making some gas probably around a 100 MCS a day, but for the most part it's a very oily area. We did then move on from that well and moved five miles to the southwest and we have drilled our third horizontal well, second producer in our third horizontal, again using the sleeve technique, pod completion and just finished the frac job on that well day before yesterday. Obviously, we have-- we've got to go in and clean it out and then open it up for flow. I will say we did do a size well in that area prior to a vertical size well prior to drilling the horizontal, two cores logs. They look as good as 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 last quarter, and we are continuing that into this quarter, and I think you will see us get back to our previous growth moving forward. And we are-- I think we were going to be very-- you are 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 in the North Gaines. And with that I am going to turn it over to David.

[David Fowler:]

Thank you, Danny. Appreciate that. Thanks for that update. For the most part, its business as usual on the leasing and the acquisition front as 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 companies that had been reluctant in the past to lead, to participate, with their minerals or in some cases their HPP 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 and increasing our net gross as well. Now over the past several months, we've seen several excellent acquisition opportunities that would be a great fit to our existing assets 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 become to terms on an 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.

[Tim Rochford:]

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

[Operator:]

[Operator Instructions] Our first question is coming from the line of Neal Dingmann with SunTrust. Please proceed with your question.

[Neal Dingmann:]

Good morning, guys. Thanks for all the details. Tim, I don't know if you want to further step to Kelly or Danny as far as-- it definitely is noticeable the big improvement in production that Kelly said on a press release on 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? Thanks.

[Tim Rochford:]

Absolutely, Neal. Listen, look, as Danny just touched on briefly and not to us, but just touched on briefly with our last call which is about midway through our second quarter, we did get off to a slow start, but we wanted to re-assure everyone that-- that was-- those are items that are going to be corrected. Danny is just underlying that that areas have been corrected and as everyone on this call knows, we've finished the second quarter of the month of June very strong, and entered into the third quarter aggressively on all levels from a growth standpoint. But I think that 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 are going into third quarter for production.

[Daniel Wilson:]

Yes, you bet. Now we-- obviously-- as we've 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, there lot of control. We have put in place and with Schlumberger, 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's borrowing the crew that there is a rig down and move off and will 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 bond earlier which put us behind on fracking and which obviously, it kicks everything down the line because you've got to clean the well frac, you clean it out and hang it on, test it and then-- 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.

[Neal Dingmann:]

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

[Tim Rochford:]

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

[Daniel Wilson:]

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

[Tim Rochford:]

No, no, Danny, look I'll turn it right back to you. All I was going to say is, Neal, it's a very good question and what we are 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 in 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 - will be-- we will get into that very soon and will be adopted and when that decision has been made. We hate these moving targets, okay, but look, gosh we are growing-- things have happened 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 are going to come formally back to the street with an amended CapEx for the balance of the year. So, go ahead Danny and add to that please.

[Daniel Wilson:]

Yes, no, just in the short term, Neal, one of the things we are working on right now, bring the planning and design process, as well as the securing right way and 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-- that Brushy well in there with those we would just knock all the other leases off line, 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'll be a couple of million dollars to do that and we anticipate that we are shooting to have that online early fourth quarter. Once that's in place then that will 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 kind of corner post the production are there-- our acreage, kind of see what it looks like across there. We think that maybe as we move down deep and maybe to the north hopefully we'll see a little more-- little oilier that's over in that area. But-- and we have-- we have secured additional space on Anadarko who we are-- it's Delaware basin midstream, but it's owned by Anadarko and that we've 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-- is to drill a disposal well. One thing I have not-- neglected to say in my earlier comment was, one thing we are very excited about in this area is that we are seeing much oil cut in these wells than we are to the south in our core area. Down there we typically see to 10% to 15% oil cut and up in this North Gaines area-- the initial test well that we worked on-- was seeing oil cuts anywhere from 25% all the way up to-- we were seeing towards the end as it was pumping down 40% oil cut. The second well the one that's the first real true producer already has oil cuts of 25% to 26%. So we are very excited about that, makes much less water. But we still need to disposal well. We don't want to have to haul all this water and drilling the disposal well probably-- maybe this quarter it's the very least-- at the very latest probably next quarter we'll get that online and now free us up to move back up in that area. We have got a lot of acreage that we are 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 there. You'll probably see our drilling kind of concentrated in that kind of an area because of the infrastructure, and then we'll build it out from there, but this second well-- second producer comes in like we hope. It's going to improve up a substantial amount of acreage being that it's five miles away, but that's kind of the infrastructure-- the major infrastructures things I see as far as North Gaines and Brushy moving forward.

[Neal Dingmann:]

Go ahead, Tim. I am sorry.

[Tim Rochford:]

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

[Operator:]

Thank you. The next question is coming from the line of Jason Wangler with Imperial Capital. Please proceed with your question.

[Jason Wangler:]

Good morning. Wanted to maybe dovetail a bit on what you're talking on the infrastructure side, in terms of timing on those things, obviously, you worked through the cost, but is there a few months' timeframe to kind of get ready before you'd be able to go out and start drilling more actively your-- how should we think about it from a timing of development standpoint on the asset?

[Tim Rochford:]

Danny?

[Daniel Wilson:]

You know 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 be shut down while we're doing the infrastructure, just wanted to point that out. As Tim mentioned, we're going sit down fairly soon and we'll work out formalized those 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 in electrical as we start up in that area. But, you know and, then so I don't anticipate in 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 are not going to move there full-time and just get busy right away. And kind of same on the Brushy, well give us some time to get this digested and then do our planning as we move forward to how we are going to get the gas into the market and then drill our additional wells.

[Jason Wangler:]

Okay. So, it would be fair to kind of think that it is 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 in that you have the infrastructure laid out. You have well data and things like that?

[Daniel Wilson:]

I think that's fair to say, yes.

[Jason Wangler:]

Okay. And then just in the core Central Basin it seems like the wells is 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 think you'll be set up for some time?

[Daniel Wilson:]

No, I think we've got 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 you know it's that-- that was kind of a pleasant surprise for us how well those wells were doing down there, and we are working to expand our acreage position, and we, but as far as the, more anticipated growth in that area, I don't see much, maybe one more additional disposal somewhere along the way.

[Operator:]

Thank you. The next question is coming from the line of John White with Roth Capital. Please proceed with your question.

[John White:]

Good morning, gentlemen and nice presentation. Danny just answered my question I was going to ask about the oil cut at North Gaines, and that is-- that information is-- those are really nice oil cut numbers that's I bet you are very pleased with that.

[Daniel Wilson:]

Very much. So it was-- it was not surprised.

[John White:]

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

[Daniel Wilson:]

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

[John White:]

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

[Daniel Wilson:]

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

[Tim Rochford:]

High pressure gas versus low pressure gas, right.

[John White:]

Well or no gas. Very nice quarter. Thanks for taking my call.

[Operator:]

Thank you. The next question is coming from the line of John Aschenbeck with Seaport Global Securities. Pleased proceed with your question.

[John Aschenbeck:]

Good morning, everyone. And thanks for taking my questions. 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 it looks like you've also drilled a few more wells there as well. Sorry if I missed it but how much acreage did you add there?

[Daniel Wilson:]

We didn't say.

[David Fowler:]

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 got become obviously more difficult but you've got a lot of majors in there. And at this point when we can add a 160 or 320 or even a 640, that's pretty - that's a big chunk. Those are harder to come by. Often times they're held by production by an existing operator and of course we've been observed but people like 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 that those doors are opening up and we're able to secure some of those chunks of acreage as bolt-on.

[John Aschenbeck:]

Okay, got it. It sounds like to me maybe that the process is ongoing. So I understand if you can't elaborate too much -

[David Fowler:]

Yes. It is. Yes, it is.

[John Aschenbeck:]

So from that point of view - 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?

[Tim Rochford:]

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 and it relates to the balance for the budget, CapEx wise, the remainder of the year. We should be able to do an update on that, give an update on that.

[John Aschenbeck:]

Okay, great. That leads perfectly into my next one. So, Kelly, your prepared remarks on the press releases here recently you spoke to the acquisition environment in the Central Basin platform companies also you 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, so to fund that deal. And then secondly if you do pull the trigger on a bigger deal should we expect acceleration to follow?

[Kelly Hoffman:]

Thanks, John. Yes, it's a good question. We have always looked at the borrowing base as a bridge if you will of course. And so depending on the type of transaction, a lot of discussions, so 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 we're better set expectations and in those discussions, there are a lot of discussions it's around different types 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, some of them are middle, and some are smaller, but they're all very exciting to us. Do I think we'll get something done? I'm very hopeful that we will without question. And I think that answered both end of your question there. If I missed part of it please restate it for me.

[Tim Rochford:]

John, let me --so just I think just add a little bit maybe more color to that as it relates to are we getting closer? You know us well enough; most people on this call know as well enough that we are 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 with 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 seen in Northern Gaines not to mention Delaware with the Brushy. That you have to kind of configure all those together and sit downs 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.

[Operator:]

Thank you. Our next question is coming from the line of Joel Musante with Alliance Global Partners. Pleased proceed with your question.

[Joel Musante:]

Hi, guys. 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 differential --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.

[Kelly Hoffman:]

Well, it's a very good question Joel and it's very good point to even spend more time on. Again, there are 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 to respond to that as it relates to the infrastructure or the takeaway issues et cetera, but there's no question that for the first time for the company so we have now multiple areas not just to do the research and development, and while we're developing in our core area but now we have multiple fronts that are going to justify development. So you can see there's going to be a lot of planning, a lot of work that's going to go into this here over the next number of weeks and months. And as Danny pointed out earlier probably through the most of this rush this year but maybe Danny if you could expand on the takeaway side of that of Joel's question as well.

[Daniel Wilson:]

Yes, and Joe, we've already started discussions with several companies in North Gaines on both takeaway or oil and gas. Those are 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 it midstream companies and build for us. Or - 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 are working on.

[Operator:]

Thank you. Our next question is coming from the line of David Beard with Coker & Palmer. Please proceed with your question.

[David Beard:]

Hey, good morning, gentlemen. My question is related little bit around spending near-term and long-term. First is near-term, it seems the variability in the quarter is sort of $30 million bucks 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?

[Tim Rochford:]

Good question. David, I think the bulk about 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 will formalize that but I think Kelly can touch on that because I know that he and Danny been working hard on this. So maybe Kelly you could drill down a little bit on that, please.

[Kelly Hoffman:]

Sure. Thanks, David, good question. Our plans right now are --we may add a disposal well here and there where we think it's necessary as these things continue expand. As Danny mentioned, will be up in Gaines few more times potentially this year. And in doing so we --as he mentioned on both the takeaway side. We are 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 to. So we'll have a little bit of a spin 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 games on the drilling side, the tweaking that we're doing going forward they are real heavy lifting, of all of that I feel like was done in the first horizontal test well in those two verticals. We don't have the need in that immediate area. I'd say area although it's a pretty large sized area about a five-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.

[David Beard:]

Good, that's helpful. A bigger picture, if you work through the rest of this year in 2019 in both Gaines and 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?

[Tim Rochford:]

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 2019 and particularly as we're getting closer to 2020. I think that's very reasonable to believe that could happen.

[Operator:]

Thank you. 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.

[Tim Rochford:]

Okay. Thank you, operator. 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, our Investor Relations or to any of us at the company and have a wonderful day, and thank you.

[Operator:]

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