Ring Energy, Inc. (REI) Q1 2018 Earnings Report, Transcript and Summary

Greetings, and welcome to Ring Energy 2018 First Quarter Financial and Operating Results. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Tim Rochford. Please go ahead.

Thank you, Stacy, and good day, everyone. I want to welcome all the listeners to our first quarter 2018 financial and operations conference call for Ring Energy, Inc. Again, my name is Tim Rochford, I'm Chairman of the Board. Joining me on the call today is, our CEO, Kelly Hoffman; our President, David Fowler; CFO, Randy Broaddrick; and Executive VP and Chief of Operations and -- Chief Operations Officer, Danny Wilson. Today, we will cover the financials and operations for the first quarter ending March 31, 2018. We will review our results and provide some insight as to current progress thus far in the second quarter. At the conclusion of the first quarter overview, we will open up the call for any questions you may have. And at this time, I'm going to ask Randy to get us started with reviewing the three months ended March 31 overview of the financials. Randy?

Thank you, Tim. Before we begin, I would like to make 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 Tuesday, May 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 three months ended March 31, 2018, the company had oil and gas revenues of $29.9 million and net income of $5.7 million, as compared to revenues of $12.2 million and net income of $1.3 million in the first quarter of 2017. For the 3-month period 2018, the net income includes a pretax unrealized loss on hedges of $791,000 and an additional tax provision of approximately $1.2 million. For the 3-month period 2017, there was an additional tax provision of $417,000. Without these items, first quarter 2018 net income would have been approximately $7.4 million, and for 2017, it would've been approximately $1.7 million. The additional tax provisions referenced are the result of changes in the unrecognized tax effect of stock-based compensation. For the three months ended March 31, 2018, our oil price received was $60.73 per barrel, an increase of 25% from 2017, and our gas price received was $3.58 per Mcf, a 10% increase from 2017. On a per BOE basis, the first quarter 2018 price received was $58.06, an increase of 27% from the 2017 price. As noted in our press release, total lease operating expenses, including production taxes for the three months ended March 31, 2018, were $14 per barrel of oil equivalent, or BOE. Without production taxes, the production cost per BOE were $11.23. This is compared to $12.26, including production taxes, or $10.08 without production taxes in the first quarter of 2017. For comparison to a more recent quarter, first quarter of 2018 is a reduction from fourth quarter 2017 of $14.58 per BOE, including production taxes, or $12.17 without production taxes. Going forward, we anticipate our production cost per BOE, excluding production taxes, to be around the $12 range, plus or minus. Most production taxes are based on values 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 DD&A, or depreciation, depletion and amortization, including accretion of asset retirement obligation per BOE increased for the three months ended March 31, 2018, to $16.82 as compared to $13.46 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, the 3-month period ended March 31, 2018, increased approximately 140% from the comparable period in 2017. This increase is the result of a combination of significantly higher production volumes and the increased depletion rate discussed above. Our overall general and administrative expense increased $245,000 for the period ended March 31, 2018, as compared to the same period in 2017. On a per BOE basis, this equates to a drop from $10.59 in 2017 to $5.99 in 2018. The decrease in the per BOE rates is primarily the result of increased production volumes. On a diluted basis, the income per share for the three months ended March 31, 2018, was $0.10 as reported. Excluding the $791,000 pretax unrealized loss on hedges, the additional tax provision of approximately $1.2 million and an approximately $1.1 million noncash charge for share-based compensation, this becomes net income of $0.14. This is compared to income per share of $0.03 as reported or $0.05 per share, excluding the $417,000 additional tax provision, and $619,000 noncash charge for share-based compensation in 2017. As of March 31, 2018, we had no amounts drawn on the $60 million borrowing base on our credit facility and had cash on hand of approximately $47 million. For the three months ended March 31, 2018, we had positive cash flow of approximately $19.2 million or $0.33 per diluted share, compared to approximately $7.2 million or $0.14 per diluted share for the same period ended 2017. With that, I will turn it back to Tim.

All right, Randy, thank you. Good job. Let's go ahead and turn it over to Kelly, our CEO, and Kelly's going to give us an overview of the operational updated thus far. Kelly.

Thanks, Tim. And thank you everyone for joining us on the call today. In the three months ended March 31, 2018, the company drilled 12 new horizontal San Andres wells, one horizontal Brushy Canyon well and three saltwater disposal wells, and was in the process of drilling two additional new horizontal San Andres wells at the end of the quarter. Of the 13 drilled wells, 12 were 1 mile long and 1 was a 0.5-mile long well. In the first quarter, the company completed, tested and filed initial potentials on 12 new horizontal San Andres wells, 11 wells were drilled in 2017 and 1 was drilled in the first quarter of 2018. The average IP on the 12 completed wells in the first quarter 2018 was approximately 436 barrels of oil equivalent, and in addition, the company had 20 new horizontal San Andres wells, which were in various stages of drilling, completion and testing on March 31, 2018. Net production for the first quarter of 2018 is approximately 507,000 BOEs, as compared to net production of 266,000 BOEs for the same quarter in 2017, that's an approximate 90.6% increase. And net production of 422,000 for the fourth quarter 2017, and that's an approximate 20.1% increase. March 2018 average daily -- net daily production was approximately 6,005 BOEs as compared to net daily production of 3,618 BOEs, the same period March 2017, an approximate 66% increase in net daily production of 5,352 barrels. So again, December 2017, an approximate 12.2% increase and the average estimated price received per BOE in the first quarter 2018 was $58.06. And with that, I'm going to introduce you to Danny Wilson, turn it over to Danny for current and future operations update.

All right. Thank you, Kelly. I want to start out by bringing everyone up-to-date on our Central Basin Platform drilling program, and then I'll finish with an update on our Brushy Canyon horizontal test out in the Delaware and our North Gaines San Andres tests. On the Central Basin Platform, we still have 2 rigs running, and should meet our goal of drilling 15 wells by the end of the quarter. On the completion side, we have gotten off to a bit of a slow start in the quarter due to several unusual circumstances, first is, we have stated in the past, even though we have a dedicated frac crew, they complete wells at a faster pace than we can drill them. And our agreement with Schlumberger is that when we catch up on completions, they are allowed to do work for other operators, usually for 2- or 3-well package. We had one of these times come up at the end of March and we loaned our crew out to another operator for what was supposed to be a 10-day period, which, due to problems on their end, turned into about a 3-week delay. This caused us to be delayed in bringing some of our wells on in the month of April. Another event which slowed our progress is the extremely high winds we've experienced during April and early May in West Texas. These winds caused our wireline crews which perforate and set the plugs during our fracking process, to shut down intermittently for periods of 4 to 8 hours at a time, while we waited for the wind to die down. And fortunately, it looks like we are moving out of this phase of the weather pattern and getting into a more stable pattern, which should allow us to get back on pace -- is allowing us to get back on pace. An additional item not associated with fracking is that due to lease commitments, we had to drill a few wells at the beginning of the quarter in areas where we had to pump the wells down for anywhere from 60 to 90 days before they reach peak production. And while the wells still performed very well, there is a delay in reaching that peak rate, which turned delays the effect on production. And one final issue we have had to deal with over the last couple weeks is a shutdown by DCP, which is our gas purchaser on the Central Basin Platform due to loss of multiple compressors, which are part of their gathering system that our newly finished gas system on the Central Basin platform feeds into. This caused a complete shutdown of our gas system for about a week, and DCP has repaired one of the compressors, and we are now selling gas at a reduced rate. Their second compressor should be repaired in the next week and we should be back up to full sales shortly thereafter. Due to the combination of these issues, we may be challenged to meet our low double-digit growth goal for this quarter. However, the only issue challenging us this quarter is the pace of completing wells, which is back on schedule at this time. We're still very pleased with the wells we are drilling, and fully expect them on average to meet or exceed our type curves and we also fully expect for Q3 and Q4 would be back on pace for low double-digit growth. Moving on to our Delaware property in our Brushy Canyon test. As you will recall, based on the studies that we've been performing out there over the last 2 years, we drilled our first horizontal Brushy Canyon test in Q1. 2 weeks ago, we moved in and fracked the well, and we've started flowback on the well last Friday. As of today, we're still recovering low water and have no results to report. One thing I would like to point out on that is it's very encouraging for us as we were able to frac that well with 100% produced water, which saved us a tremendous amount of money, and also saved us from many logistical problems in the future that we have to deal with as far as getting water supply out there, which is somewhat limited due to the desert environment. We should have much more to talk about in our end-of-quarter press release in early July as far as the Brushy Canyon well. As far North Gaines properties, based on the results we saw in our initial signs wells, which we drilled last year, we moved in and drilled our first horizontal well in Q1. We are using this well to test several potential completion techniques. Basically, we are completing the well in up to 4 different phases. Our first phase is completed in Q1, resulted in excellent oil cuts but somewhat limited fluid entry. Since that time, we have completed a second section of the well, with a different technique, which resulted again in a very good oil cut and a much better fluid entry. By the end of Q2, we should have completed an additional 1 or possibly 2 segments of the well. We hope to have a much more detailed report for everyone at the end of the quarter. I will point out that even though we haven't finished testing the initial well, we're very encouraged by the results we are seeing and have begun staking additional locations at this time. And with that, I'm going to turn it over to David Fowler.

Thank you, Danny. On the land side, we continue to refine and high-grade our leasehold on the platform and are currently in various negotiations relating to the continued leasing and acquisition opportunities. As all of you are aware that area on the platform that we operate has an extensive number of these sponsored teams that are under a 3 to 5 year tracking starts monetization, and a good number of those are approaching or have already passed their 5-year maturation. And I'd say, starting towards end of last year and it's continued into this year, we've seen a steady flow of acquisition opportunities. We take extensive steps to fully vet each deal that we evaluate, with the ultimate objective, to negotiate favorable terms so the addition of those new assets become immediately accretive to our company and our shareholders. In the current environment, we're willing to broaden our landscape, but stay within our playground and as you'll remember, we described our playground as a 2-hour drive, which is the radius around Midland. And as a final thought, I'd say that our greatest advantage is the significance of our financial flexibility that gives us a tremendous benefit in competitive situations to move quickly and decisively, just a great position to be in. I'll now turn it back over to Tim, for closing comments.

Okay, David. Good job. Good job, everyone. So this concludes the company's portion of the first quarter financial and operational overview. What I'm going to now is turn it back over to Stacy, our operator. And Stacy, you may open it up for questions that we may have.

[Operator Instructions]. Our first question comes from Jason Wangler with Imperial Capital.

I wanted to ask on the DCP issues. It sounds like that's kind of a one-off issue, but are they pretty fold up their? Or how do you see kind of that playing throughout the year as you as bring on some more production and obviously, have your pipeline up and running?

Yes, good question, Jason. Danny, go ahead and take that if you would, please.

Yes, we don't see this being a long-term problem. I think what happened, Jason, is that when we brought our system up, it put a little more strain on their system due to the volume we were sending down than they were anticipating. And I think some of their equipment obviously too, is -- was a little out of date, and with our increased production coming into the system, they just -- they had 1 failure, and they decided while they had that one down to go ahead and had the repair crews out there, to go ahead and work on the second compressor. So it's just been a bit of a delay. When they brought up the first compressor after they got it repaired, everything looks good. We're selling at a slightly reduced rate, but we anticipate that the second one will be back on. Right now, we are not seeing any indication from DCP or heard anything from them that indicates this is going to be an ongoing issue.

Okay. And then you mentioned that -- just sounds like you guys are just completing wells so fast, it's the just-in-time situation. Is there any thought on either building a backlog of more wells or even bringing another rig at some point, given where oil prices are, to kind of balance that out so the completion crew and the rigs kind of stay busy in tandem? Or just how should we think about the plans going forward there?

And you're making, reference, Jason, to the completion rigs?

Yes. It sounds like -- I think in the prepared comments, just mentioning the fact that the completion guys did such a good job that they ran out of wells to complete. So I'm just wondering how you look at either building an inventory or matching how many rigs would go with the crew as you get more efficient, or just what the thought is there, so maybe you don't have to get -- you don't have to lease them out. So it sounds like somebody had a bit of a problem with them.

Sure, and that's an excellent point. So I can share this with you, and then Danny, you can put, add a little more color to this, if you like. It is our intention to continue the pace that we're on as it relates to drilling, and continue to hopefully improve upon that lag time. If you're only looking about the fourth quarters last year and then coming in starting this year, we've done a pretty good job of keeping that momentum going. Now, as Danny admitted, we have a bit of a slow start, and there are a number of different issues, any one by themselves probably wouldn't have made a big difference, but collectively, they did. So I think the important part of that is, is that we've got that realigned now, we feel comfortable going forward. As it relates to adding yet another rig, listen, we're seeing some robust numbers right now as it relates to the commodity space. And so, we're looking at that closely, of course. But we have some really good thoughts and ideas that we're kicking around internally as it relates to the remainder of this year, and so as time goes on, we'll see how that goes.

Maybe just to sneak one in, just a follow-up on that, Dan. Maybe there was just a onetime issue or something, but does the 2-rig program basically keep that completion crew busy on a steady run rate, and there was just some issues that came up? So should be think of it that way?

Yes, Danny, go ahead and feel...

No. No, they, Jason, they definitely can complete them faster than we can drill. It would take a 3-well program to keep them busy full-time, and as Tim pointed out, obviously, it's something that we think about, but we haven't made that decision at this time.

Our next question comes from Neal Dingmann with SunTrust.

Kelly, for you or Danny, you gave a good explanation on the Northern Gaines, but I guess, I just want to get a little more color on this. Maybe if you could just talk about your thoughts on, Danny, a little bit more on the timing on this, I guess, where I'm going, it seems like there's been a bit of investor concern around the stock, given the timing on this one versus how quickly you've been drilling all these other wells. So I just -- maybe if you could, just maybe a point of clarification, what's going on up there?

Absolutely, no. What we did on this well, Neal, in the area that we started out, in the Central Basin Platform, we had at the luxury of sitting and watching people for about 5 years as they refine the completion techniques in that area. And so we were able to pretty much hit the ground running when we started there. And in the area up in North Gaines, this is a new frontier for the San Andres. There's a lot of San Andres production up there, but nobody has drilled horizontally. And so what we're trying to do and what we're working through is what's the optimum completion technique? And so what we've done in this particular well, when we drilled it, we drilled a mile long lateral and we ran a series of sliding sleeves in the well, so that we can go in and we'll open a certain number of those, and then, say, in the first -- we opened up the first 10, earlier a bit in the quarter, or maybe last quarter. And went in and just did some light stimulation on it. We didn't want to -- we didn't want to overdo it right off the bat, and cause problems, so what we're doing is we're just kind of stepping up the completion each time, so we went into that first section, had excellent oil cuts, we were seeing 25%, 35% oil cuts. We just had somewhat limited entry. So what we did is, then we came in and did that the next eight -- I believe, we did eight stages in the next, or we opened eight sleeves, and went in that a larger frac job and still feel like we can go larger. But what we saw was, we got much better fluid entry on it. We're seeing extremely good oil cuts, even higher than the first stage. And so what -- it just -- what we're trying to do is make sure that we work through this process in a very diligent manner, but also a very structured manner so that we can see as we complete this phase, okay, here's the results, now we're going to move to -- I would say, we'll definitely be moving to the third phase of the completion trial. I would say towards the end of the month, of this month, and based on the results we see there, we may even get an additional phase done. We can probably get up to 4 different phases done in this 1 well. But, as I said though, I think we've seen enough right now, at least, in the area where we're working, I can say this across the whole 33,000 acres, but I can say in the area that we're working, we're very encouraged with the results we're seeing and we feel confident enough that we've gone out, starting staking additional wells.

Very good, and then Tim, just 1 follow-up, maybe for you or Kelly. Just when you look about the overall operational or financial budget that you have right now, my question is, given what -- sort of 2 things around that, given what's going on with oil, obviously, to the upside, would either continued higher oil prices, or if Danny and the guys have just tremendous success, either in that Northern Gaines or Brushy, would any of this increase your overall budget? Or would it just sort of take away from what you have? Maybe if you, again, just wondering how you'd look at the overall budget and what could influence it?

Sure, sure, good question, Neal. Well, to begin with, I want all the listeners to know that we're still focusing on positive cash flow by year, and that was our goal, that's the pace that we're on and we're feeling pretty comfortable with that. However, with this robust increase that we've seen, there is no question with what Danny just explained, and Danny's taken a very conservative approach to this, and we all are, and we should. But if this continues to unveil as we are hoping and what we're kind of now building our confidence in, it would be very likely that will either -- it's either the Brushy end on the Delaware side, or the northern end of Gaines County that we could expand the drilling program and adjust the CapEx upwards as a result of that, no question.

Our next question comes from Mike Kelly with Seaport Global Securities.

Just hoping to dive into this Gaines well a little bit closer, too. So it seems like there's still a decent amount of science left here. What is kind of the expectation for maybe unveiling the results here? I mean, do we get an IP rate that could stack up versus Andres? Or is it going to be little bit more methodical, kind of really, I guess, laid out differently than how you would in Andres with this initial test?

Yes, Danny, go ahead.

You bet. Mike, one thing I need everybody to keep in mind is, we never really intended that this well to be a full-fledged producer. It is really -- just been a well for us to go in an experiment with decent -- or with completion techniques. We are seeing very good results and I think probably, I would guess that we'll probably be able to share more direct results after we finish completing the three -- the different phases -- possibly Q3, could be a time when we would probably give more color on that.

Okay, fair. And your results in Andres our world-class. I mean, the highest IRRs we have of any company we cover here. And just, like to get your sense, I mean it's early days with -- in both Gaines and then on the Brushy, but how do you think returns could ultimately stack up on those 2 plays you're testing now versus what you're doing in the Andrews and the San Andres?

So Denny, as we see was been delivered thus far through our process of testing and so forth at different phases, and I know you're guarded, and we need to be guarded and conservative on this. But with what you're seeing, and I know what we've been discussing over the last number of weeks, your encouragement measurement has gone up substantially, would you think that where looking to duplicate something comparable to what we've seen to the south? Or do you think it could be higher, lower, somewhere the same? I think that's a fair question that Mike's looking for, maybe others on the call as well.

I would hesitate to say it'd be higher, because of the results we have in our existing properties, it'd be hard to outdo that. I think there's a possibility it could be equal to -- it's still very early. On the north Gaines project, Brushy Canyon, we've looked at offset wells, drilled -- just north of us, 3 or 4 miles up in New Mexico, and those results were probably equal to the results we're seeing in our existing properties. But again, those were, those are tested, they're a little far away, and this is our first attempt at the Brushy Canyon in our area, so I'm encouraged. I think there's every possibility they could be just as good. But again, that would put some qualifiers on that. It's very early.

Our next question comes from John White with Roth Capital.

Again, one more time on North Gaines. Danny, you described the different, some differentiation between Phase 1 and Phase 2. Is that in the force of the frac in terms of barrels per minute?

John, it really had to do more with the size of the frac. The rates were pretty typical. We started out there first phase, we did some acid work on it and then followed with a very live frac. The next frac that we did was about 2.5x bigger than the first one. And also, I'm being somewhat vague in this because I know we have a lot of competitors out there, and obviously, we don't necessarily want everybody to know exactly what we're doing. But we feel like we've got room to ramp up the completion, at least the volume again and so, we're just trying to see how far we can go before we cause ourselves any problems, really, and then -- and optimize the frac, moving forward. But we don't want to go after, and start drilling our horizontal wells without really knowing what our final completion technique's going to look like.

Okay, so mainly amount of profit is the variable?

That was the main variable, right.

I appreciate that. David, I found your comments to be, regarding M&A, to be a little more optimistic than usual. Is that a fair characterization?

John, we're seeing a lot of opportunities. Yes. So we're keeping our eyes open and taking the time to vet the various projects that come across our desk.

Our next question comes from Jeff Grampp with Northland Capital Markets.

So a question, I guess, back on the M&A side of things, given what we're seeing a little bit with Permian oil prices relative to -- outside of the basin, was just kind of curious how that maybe impacts either the boots on the ground, bolt-on leasing or some larger packages in those discussions, if at all, would be great to get some color on?

Yes, David, go ahead.

To make sure I understand, your question was relating to what the commodity price has to do with our...

I guess maybe not the commodity price specifically, but just within Permian oil prices and the differential's kind of widening, does that maybe make your job easier or harder to get deals across the finish line?

It really doesn't impact us one way or the other at this point. Jeff, we're just doing fine. I mean, what's nice is -- our takeaway is a different crew versus than what the majority has been produced out here by -- on the Midland and the Delaware side. So our takeaway is in good shape. And as far as leasing is concerned, we still have a lot of -- there's -- on the platform, we're talking about [indiscernible] that are relatively older, so a lot has been leased and held over the years. But we continue to have a lot of capacity in the way that we follow-up with mineral owners and also people that have those rights held. So we are continuing to pursue areas that we like and are still having really good success in getting some of those leases bought in-house.

Jeff, let me, this is Tim. Let me expand on that. That was -- David, good answer. Kind of twofold. So one is, is that we're continuing to focus on the platform, and as everyone knows, we have great assets on the Delaware, and we're not ignoring that. And as you know, we're in the phase of completing that Brushy, everyone was encouraged. But we continue to really focus on the platform. There are number of opportunities that David touched on in his earlier talking points, that as we wrapped up last year, and we entered the early part of this year, we're seeing more and more of that. A lot of these ideas are certainly familiar to people. They're, not public companies, but they're private-equity-backed teams. And again, we're trying to continue to keep the focus on the platform. We're seeing opportunities, and we are, we're following leads and we're following ideas. And so I think what David really meant earlier was -- and this is, the listeners should interpret is, is that we're enthusiastic with more and more of the opportunities that are starting to develop for us. As far as the takeaway or the differential, right now, and correct me if I'm wrong, Danny, I think we're probably seeing about a $3.50 plus or minus differential from NIMEX. Is that close, Danny?

It is. But what we do, and I think everyone's well aware, and it's still very well-publicized, that the differentials are growing in the area. We haven't see that effect yet on our particular properties, but it is something for everybody to keep in mind. I would say it's been very well-publicized. We're talking to our marketing consultants, they don't see takeaway as an issue for us in particular because of our relationship with Centurion Pipeline. But the one thing we don't know is what the differentials are going to do in the coming months.

All right, understood. And I appreciate those comments, guys, and I guess just circling back on the completion side, and I understand there were some delays, kind of third-party related. But given that it sounds like it's more on the completion side versus the drilling side, is it fair to conclude that you guys could probably catch up with things in the back half of the year as the frac crew comes back and starts catching up with the rigs?

Jeff, you're dead on with that. It really wasn't anything other than the weather issues that we had. The winds out here. If you haven't been out lately, but they have just been horrendous for the last 6 or 8 weeks. And that did put us behind. And then Schlumberger has asked us, when we have these lulls in our completion, if they can have a minimum of 2 to 3 well packages to go out and market, because that's a good -- it's hard to get one-offs, but they can sell 2 and 3 well packages. So we really worked with them on that. They've been very, very good to work with, and we're trying to keep that relationship in a good place. So when we let somebody go, we will anticipate them get back to us pretty quick. But these other folks had some mechanical issues with their wells and it set us back, waiting to get that crew back. But those issues have all been settled, and we're back on pace and I think your comment is right, that all it really did was maybe delay some of that into Q3 and Q4.

Our next question comes from David Beard with Coker Palmer.

A micro and a macro question, just to follow-up on Northern Gaines, I think you mentioned like a 25% to 30% oil cut. Is that oil compared to total water and fluids?

Yes.

Okay, that's helpful. And then bigger picture, if you guys were to choose to add rigs, just could you provide some color relative to where you might want to continue to outspend in the next year, or how that would look and sort of how much outspend would you tolerate if you were to add more capital spending?

David, that's a good question. It's a bit of a moving target as I know you can appreciate, because you have Delaware that could be involved in here very rapidly. You have Northern Gaines that is evolving very rapidly, and then you have yet the other component, which David has touched on, and that is the opportunities on the platform that we're seeing in our own backyard, our own little playground, if you will. And anyone of those components or a combination of that can change things up quite quickly, particularly, again, as we've mentioned a few times here, with the improvement in the price of crude. So we -- look, the nice thing is, is that we're well-postured. We have a great balance sheet, I don't know if there's a better balance sheet in our universe anyway, and we -- so we're ready, and we're not only ready but we're postured and looking for that opportunity in any of those flanks, any those components to just have a good reason to expand. So whether it's through some kind of ongoing growth with opportunities that we're seeing, or whether it's the development in the Delaware or whether it's a development in Northern Gaines. Any combination of those, we're ready to do so. But it will take a little more time for us to really get beyond some of those thresholds before we can actually lay out a plan for that, that to be definitive.

[Operator Instructions]. Our next question comes from Mike Breard with Hodges Capital.

I just want to ask a couple of questions. One, you showed the average IPs for the wells you bring on each quarter, could you give us some idea of how the average IP's around for your 0.5-mile wells and your 1-mile wells and 1.5-mile wells?

Yes, Danny?

Yes. The IP's on, obviously on the shorter ones are less than the 1 mile. We -- those -- I don't have the number right in front of me, Mike. We can certainly look into that and get that out, but they are somewhat lower, and that has caused, like we mentioned last quarter, we had a 0.5-mile well in there, which kind of brought our average down just a hair, I mean we went from the 4 50s into the 4 30s. It didn't make a big difference. But the difference really has less to do with the, probably the IP than the EUR in the end. But there is a slight difference in those, depending off the link as far as IP, goes I just don't have those right in front of me.

Okay. So I'm just thinking some people get the idea, let's say the average IP drops, if the wells are not as good when actually it could be better but you're shorter. Also, could you mention comments on the reactivation of some of these wells, the cost and the impact?

As far as the cost on the wells, we have seen some upward pressure on costs, mostly in the area. Two things, labor and then steel prices, obviously, are starting to creep up with the tariffs that are being contemplated by the government. But we are seeing a lot of competition in the labor market for hands on the drilling rigs, for frac crews, and that is putting some upward pressure on it. After we get done with this phone call, we have a new corporate presentation that we're going to upload onto our website, and it will have some updated AFE cost. We've changed our AFE cost from $2 million for the 1 mile to $2.2 million. And we've moved from $2.4 million to $2.6 million on our 1.5-mile wells. And -- but we also took it into account, the added pricing that we're seeing. So we bumped those up from $45 to $50 in realized price. The numbers are very similar but -- so we are realistic about our cost moving forward. We do see some upward pressure, but the pricing is more than offsetting any increases we're seeing on the AFE side.

Okay. But the wells you've reached in, [indiscernible] is that going to be an ongoing program? And what are the parameters on that.

Right, Mike, and I'm sorry if I misunderstood that first part of that question. But no, the restimulation program, and what we've found on that is, like other operators in the areas, time goes by, we'll have some issues mechanically with the well ore typically what we're seeing. In our area, we see some iron sulfide buildup. And so what we monitor on that is we wash these curves and then we see one deviate from its normal coupon rate, obviously, that's an indication that something is going on down hole. So what we've started doing is we've gone in and we've started cleaning the wells out, then using the isolation tool, we've gone in and isolated each set of perforations and we're going in and acidizing those. And we've been very pleased with that. On -- for the most part, the wells are coming back better than they were before, not necessarily as far as initially, but from where they were when they started deviating off the curve. And so I do think that will be an ongoing program. We're going to look at it. It's not something I'd say you just say, "Okay, once a year, we're going to go and clean every well out." It really depends when we start seeing it deviate from its normal curve. So -- but I do think you'll see us doing that, those on a regular basis moving forward.

Okay, but you're talking about spending a couple hundred thousand and getting a pretty nice increase in production? Or [indiscernible] payout?

You bet. Just an example on one of the wells we worked on, this well, 6 months ago, was making about 100 -- a little, about right 100 barrels a day. Over the next couple of months, we saw it drop off pretty rapidly, down to about 22 barrels a day. We went back in and did the work on it, and it jumped back up into 130 barrel range. So when we look at the payout on that, it's usually anywhere we've calculated. On the ones we've done, anywhere from about 1.5 months out about 4-month period. So they get a pretty rapid payout.

And Mike, this is Kelly. I want to add something to that Danny didn't cover there, and that is, there's not a timeliness as to this. We might have 1 well that might do this after 12 months, it may take another well two years to actually create that effect in the curve. So it's not as consistent from well to well basis. So some you'll do soon than others, and others may take longer periods of time for you to get in on.

I guess, I'll ask one more question. I assume some of these acreage you're looking at might be North Gaines? You may not want to comment.

I'm sorry, so the question, again?

Is some of the acreage that you're looking at purchasing might be in North Gaines County? But I don't know if you would want to comment on that?

Well, we can't, Mike, as you know, we're not going to be able to give a lot of color on that. But we're constantly looking north to south throughout the platform, through up the Northwestern shelf, through down the southern end of the platform itself. So they're -- but to isolate that right now would be -- would not be the thing for us to do.

There are no further questions. I would like to turn the floor over to Tim for closing comments.

Okay, thank you, Stacy. Well Listen, we appreciate everyone taking their time today. We know it's a busy time, and as always, our door is open. Feel free to follow up with any calls or questions. we'll be happy to address that. Everybody have a good day. Thank you.

This concludes today's conference. Thank you for your participation. You may disconnect your lines at this time.