Ring Energy, Inc. (REI) Q3 2017 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy Inc. 2017 Third Quarter and Nine Months Financial and Operating Results Conference Call. At this time all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [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. Thank you, Mr. Rochford. You may begin.

Thank you, operator, and we want to welcome all our listeners to our third quarter and nine months 2017 financial and operations conference call for Ring Energy. Again, I’m Tim Rochford, Chairman of the Board. Also joining me this morning on the call is our CEO, Kelly Hoffman; our President, David Fowler; our CFO, Randy Broaddrick; and Danny Wilson, Executive VP in charge of operations. Today, we will cover the financials and the operations for the third quarter and 9 months ended September 30, 2017. We will also review results and provide some insight, asked our current progress thus far, in the fourth quarter. And at the conclusion of the overview, we’ll turn this back over to the operator and open it up for any questions you may have. With that said, I’m going to turn it over now and ask Randy to review the financials for us. 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 will refer you to our release issued Wednesday, November 8. If you do not have a copy of the release, one will be posted on the website at www.ringenergy.com. For the three months ended September 30, 2017, the company had oil and gas revenues of $16.6 million and net income of $3.1 million, as compared to revenues of $7.8 million and a net loss of $5.9 million in the third quarter of 2016. For the 9 months ended September 30, 2017, the company had oil and gas revenues of $43.4 million and net income of $6.3 million, as compared to revenues of $21 million and a net loss of $37.2 million in 2016. The increases in revenues are the result of increased production and an increase in the average realized oil price as compared to the same periods in 2016. The primary factors behind the changes in net income are the increased revenues I just referenced and not having a ceiling test write-down in 2017 versus a pretax write-down of $9.6 million for the 3-month period and $56.5 million for the 9-month period ended September 30, 2016. For the three months ended September 30, 2017, our oil price received was $46.17 per barrel, an increase of 13% from 2016, and our gas price received was $3.13 per Mcf, a 4% increase from 2016. On a per BOE basis, the third quarter 2017 price received was $43.75, an increase of 19% from the 2016 price. For the 9 months ended September 30, 2017, our oil price received was $46.56 per barrel, an increase of 27% from 2016, and our gas price received was $3.19 per Mcf, a 32% increase from 2016. On a per BOE basis, the 9-month period ended September 30, 2017, price received was $43.97, an increase of 34% from the 2016 price. Production cost per BOE for the three months ended September 30, 2017, increased to $11.20, as compared to $10.94 in 2016. For the 9-month period, production cost per BOE decreased to $10.62, as compared to $10.94 in 2016. Going forward, we anticipate our production cost per BOE to be below $12, but we continue to use $12 in our internal models. Most production taxes are based on value of oil and gas sold. So our production tax expense is directly correlated to the commodity price 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 September 30, 2017, to $12.97 per BOE as compared to $12.65 per BOE for the same period in 2016. Our total DD&A per BOE increased for the 9-month period ended September 30, 2017, to $14.04 per BOE, this compared to $13.87 per BOE for the same period of 2016. 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 83% for the 3-month period ended September 30, 2017, and approximately 56% for the 9-month period. This increase is primarily the result of increased production volumes. Our overall general and administrative, or G&A expense, increased $487,000 for the three months ended September 30, 2017, as compared to the same period in 2016, and $1.6 million for the 9 months ended as compared to the same period in 2016. On a per BOE basis, this equates to a decrease from $8.84 in 2016 to $6.23 in 2017 for the 3-month periods, and from $9.39 in 2016 to $7.68 in 2017 for the 9-month periods. The increases in total were primarily the result of an increase in stock based compensation of $404,000 for the 3-month period and $1.1 million for the 9-month period as compared to the same period in 2016. On a per BOE basis, the decreases – well, the increases in the total were more than offset by the increases in the production cost – or production volumes, I’m sorry. On a diluted basis, the income per share for the three months ended September 30, 2017 was $0.06. Excluding the $960,000 non-cash charge for share-based compensation, this income is increased by approximately $0.01 per share for an income of $0.07 per diluted share. This is compared to a loss per share of $0.14 as reported, or a gain of $0.01 per share, excluding both a pretax ceiling test write-down of $9.6 million and a $556,000 non-cash charge for share-based compensation in 2016. On a diluted basis, the income per share for the 9 months ended September 30, 2017, was $0.12. Excluding the $2.8 million non-cash charge for share-based compensation, this income is increased by $0.04 per share for income of $0.16 per diluted share. This is compared to a loss per share of $1 as reported, or a loss of $0.01 per share, excluding both a pretax write-down of $56.5 million and a $1.6 million non-cash charge for share-based compensation in 2016. As of September 30, 2017, we had no amounts drawn on the $60 million borrowing base on our credit facility and had cash on hand of $40.8 million. For the three months ended September 30, 2017, we had positive cash flow of approximately $10.3 million or $0.19 per diluted share, compared to approximately $3.7 million or $0.09 per diluted share for the same period in 2016. For the 9 months ended September 30, 2017, we had positive cash flow of approximately $26.3 million or $0.51 per diluted share, compared to approximately $8.1 million or $0.22 per diluted share for the same period in 2016. Before I turn the call back over to Tim, I would like to share where we are in the process of the redetermination on our borrowing base. While it’s not finalized, we are quite confident that we will see another significant increase on our borrowing base. We expected to be increased to $125 million from the current $100 million. That being said, to avoid unnecessary costs, we have requested that the commitments related to the borrowing base remain at $60 million until we deem at prudent and elect to have that amount increased. With that, I will turn it back to Tim.

Okay, Randy, thank you. Appreciate that. We’ll now turn it over to Kelly Hoffman, our CEO, and Kelly’s going to review the quarter’s activities for us. Kelly?

Thanks, Tim, and welcome, everyone. In the three months ended September 30, 2017, we completed the drilling phase of 12 horizontal wells and have initiated drilling on two more on our Central Basin Platform asset. We have completed and are currently in the cleanup and testing phase on four of the new wells drilled in that quarter three 2017, as well two wells that were drilled in the second quarter 2017. For the 9 months ended September 30, 2017, we drilled a total of 28 horizontal wells and one vertical well in the CBP asset. In addition, we drilled two new solar disposal wells and performed extensive work on upgrading our oil, gas and water handling systems. And in our Delaware asset, we drilled four vertical Cherry Canyon wells, performed recompletions on two existing Cherry Canyon wells and we also drilled one new solar disposal well. And we continued to upgrade the systems for gas and water handling there as well. Production for the three months ended September 30, was approximately 376,000 barrel of oil equivalent, as compared to net production for the same period of 209,000 BOE in 2016 and that’s an approximate 80% net production increase. The net production of 330,000 BOEs for the second quarter 2017, and that’s about an 11% increase. Now in September 2017, average daily production was 4,345 barrels of oil equivalent as compared to net daily production of 2,270 barrel of oil equivalent in September 2016, and that’s a 91% increase in net daily production of 4,110 barrels of oil equivalent in the second quarter. The average price received per barrel in the third quarter was $43.75. For the 9 months ended September 30, net production was approximately 980,000 barrels of oil equivalent as compared to 625,000 barrel of oil equivalent for the 9 months ended September 30, 2016, that’s an approximate 57% increase. Our average net daily production increased to approximately 3,614 barrels of oil equivalent per day and the average sales price was $43.97. In mid-August, we added our second horizontal drilling rig on the Central Basin Platform and we estimate we can drill about 5-plus wells per month with – that’s actually running both the rigs. And we also have secured a dedicated frac crew from Schlumberger which started about 2.5 to three weeks ago, and Danny is going to shed a little more color on that here in just a moment. With that, I’m going to introduce you to Danny Wilson, he’s our EVP and he’s head of operations. Danny?

Thank you, Kelly. As Kelly mentioned, we began our 2-rig horizontal drilling program in the second quarter. And as of today, we have just finished our 37th well for the year. At the current pace, we should be able to finish drilling between 45 and 47 wells by year end. Beginning on October 14, Ring Energy now has a 100% dedicated frac fleet. This is a highly experienced team and we’ve been extremely pleased with the quality of both the crew and the equipment. And as of today, they are working on their sixth completion for us. Due to the carryover of wells waiting on completion from the third quarter, we also brought in a second crew to frac a couple of wells and assist us in getting us on our completion schedule. It typically takes around 30 days from the time we release a drilling rig until the well is put on production. The flowback and cleanup after that is anywhere from two weeks on the low end to as much as three months on the high end, which means we will start seeing results from this more consistent completion activity as we move into the latter part of this quarter and on into the first quarter in 2018. And although we don’t give formal guidance, we are expecting double-digit growth for the quarter. Today, our wells have been outperforming our type curve, which per 1 mile lateral has initial rate of around 350 BOE per day and around 550 BOE per day for the 1.5 mile wells. We continue the use a 55 BOE per lateral foot recovery for our modeling, even though we are seeing better results than that. In fact, our third-party engineers have given us credit for recoveries on the mid- to upper-60s per foot. Our drilling costs have remained consistent in the $2.2 million range for the 1-mile wells and $2.6 million for the 1.5-mile wells. And I want to point out that these are all-in costs including leasing and facilities. As these recoveries in costs and at a net $45 per barrel, we continue to see internal rates of return of 102% and discounted returns on investment of 2.9:1 for our 1-mile wells, and 250% IRRs and 3.8:1 ROIs on our 1.5-mile laterals. And in addition to the activity on our regular development areas of Andrews and Southern Gaines Counties, I wanted to bring you up-to-date on our work in Northern Gaines County, which is part of our acquisition of acreage from Devon earlier in the year. To date, we have drilled two vertical signs wells, one of the north central part of the acreage and another in the southeast quadrant. We ran extensive logging and coring suites and we’re encouraged with the results we are seeing. Our plan at this time is to move forward with the drilling of an additional vertical signs well, which will begin in the next couple weeks as well as the spudding of our first horizontal well within the next four weeks. And with that, I’m going to turn it over to our President, David Fowler, to report on our land and acquisition activity.

Danny, thank you very much. At the end of Q3, our acreage total for the Central Basin Platform and the Delaware Basin combined, this would be the Texas total, was 124,000 gross and 91,000 net. Focusing on just the platform, we currently have approximately 103,000 gross acres and 71,000 net, now that’s vertical and horizontal acreage combined. And then to isolate just our platform horizontal acreage total, we currently have approximately 94,000 gross acres, 70,000 net, and that puts us at about 91% of our platform acreage that currently lies within our horizontal target area. We continue to pursue bolt-on leasehold opportunities and remain focused on narrowing the net to gross gap. The land department is also doing some tidying up that you would maybe consider small bites, but are essential to increase our ownership in particular leads or fill in a small gap that will shorten the drilling unit. We continue to see significant AD activity on the platform and make it our business to stay informed on the new companies coming into the play along with communicating with the management teams that have been in the play so that we stay informed of what’s going on. As we end up the year, we remained well-positioned with maximum financial optionality to consummate acquisition opportunities that become available that meet our criteria. And now I’ll turn it back over to Tim for closing comments.

All right. Thank you, David. Guys, good job. I would like to just add this, and of course, most of our listeners know that we do not provide formal guidance. But with that said, I can tell you that the current pace that we’re on, the two rigs that are running on the platform and albeit, this has to be in absence of any major acquisition or any major leasing activity, we’re on target with the resources that we have at hand. We’re on pace to reach a positive cash flow by early- to mid-2019. Along with that, that also assumes an average of a $45 realized price per BOE. But with that, I will turn us back to our operator. And operator, if you’d be kind enough to open it up for questions.

Thank you. [Operator Instructions] Our first question comes from the line of Ben Wyatt of Stephens, Inc. Please proceed with your question.

Hey good morning guys. And congrats on the susses in the Central Basin Platform. My first question has to do with kind of the growth that you guys have seen and kind of continuing that growth as you guys kind of grow into your CBP asset over time. So I guess, kind of my question here is, as I think about Ring going from two rigs today from, call it, four, six or whatever the number ends up being over time, do you all feel like you are adequately staffed to do that? Or is there quite a bit of change on the headcount front that needs to happen for you guys to execute a much bigger drilling program?

Good question. Danny, why don’t you take that?

You bet. Ben, we’re already in the process of doing that. We’ve added another engineer here in the last couple of weeks and then we’ve also staffed up in our field operations. We are starting to add people into our completions team. We’ve added people into our drilling team and now we’re working on staffing up on the construction side. So we are already in the process of handling that as far as staffing goes.

Great. Good to hear. And then kind of a second question here, and I appreciate you guys giving us some color on that northern block in Gaines. But as I think about kind of the other big block, if you will, that kind of hangs around the Gaines, Andrews border. Know you drilled wells around the border there. Kelly or whoever, just curious if you guys could maybe walk us through kind of how far you’ve stepped out kind of across that bigger block down to the south?

Sure, Ben. When we started our initial program in 2016, just thinking about that as the pivot, if you will, in stepping out, we did step out some wells in the first quarter of this year that were about 2.5, 3 miles to the east and we had some that were as far as 8 miles to the southeast. We’ve now gone north probably 3 or 4 miles. So we’ve managed to spread that footprint out, you can tell by those numbers, substantially. I mean, then as we move up into Gaines County, it’s even – I mean, that’s going to be 15 , 20 miles away. So we’re really establishing. And those test wells Danny spoke of are probably 15, 16 miles apart. So we’re strategically putting those in which we always do prior to drilling horizontals.

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

Good morning guys. Tim, my question was kind of asked but you kind of baited me into the question, Tim. You mentioned in the comments about the free cash flow, I know that seems to be topic du jour out there. Can you tell me, Tim, for you or Kelly, or even Randy, what sort of assumptions as far as to get there into either mid – early to mid-2019 as far as the amount of rigs that you’re assuming in that? I don’t – because again, I know you don’t have cognizant of 2018 or certainly not 2019, sort of spending specific numbers out. So just wondering sort of general thoughts around there as far as to get to that, is that assuming two rigs, four rigs? And any other sort of general assumptions that would be built in there?

Certainly. Good question, Neal. I’m glad you asked that. Actually that’s supporting two rigs. And of course, as I prefaced the comment, that’s in the absence of any significant acquisition or it’s in the absence of any change in even the possibility of accelerating. But with the two rig program, from this day forward, and we’ve taken a very conservative approach to this. And then I guess, you maybe have to ask yourself, what’s the likelihood that you wouldn’t have an acquisition or you wouldn’t have an opportunity for maybe possibly a larger lease block that becomes available. As David mentioned in his comments, we’re looking and we’re watching closely what’s going on in the platform. We do believe opportunities are going to avail themselves as we go along. So it’s likely something like that happens. But my point was, in the absence of any of that, just pure today, because so many people, and rightfully so, focusing on what does it really take for you to be cash flow positive, supporting a program that you have now, which what, that program that supports growth. Two rigs on the platform through 2018 on into early mid-2019, $45 realized price, we turn positive cash flow.

And Tim, that has assuming all costs. I know some of the companies I follow, they might back out some infrastructure, they might back out some capitalized cost, does that include everything in there?

Yes, it does. As a matter of fact, it even anticipates a bit of an increase as we go along, which we anticipate. But it also, just so the listeners have a good feel for this, as we go through 2018, our CapEx expenditures, based on what we just talked about, even though we have yet to put out our CapEx for next year, that includes, not only miles, but some 1.5 miles sprinkled in there. As we enter into year 2019, there are very few, if any 1.5 miles, most, I believe, are all 1 miles. Would that be correct, Danny?

That’s correct.

Yes. So knowing that, Neal, there’s – we’ve really kicked in everything from A to Z, factoring in and crunching those numbers. So we feel pretty confident about it.

Okay. And then the last one. Kelly, you mentioned earlier, you talked a lot about logistics. And again, there’s always – especially for smaller companies, as you’re ramping as quickly as you are. Could you talk a little bit about that? I mean it seems like there was some timing issues you might say and a little bit in first, second quarter, but you guys have been, to me, fully ahead of schedule or ahead of the plan. Trying to put all these logistics on sort of online. I guess, my question is when you look at 2018 versus 2017, will you have to continue to do as much of that? Or will the spending be as much? I’m just wondering if you can sort of quantify that at all?

Sure. Thanks, Neal. As it relates to expansions, when we went from one vertical rig to two vertical rigs to three vertical rigs, we spent a lot of money time and effort expanding the infrastructure associated with that expansion. It’s no different as it relates to horizontal. In the second quarter, we had a completion quarter, it was pretty strong in completions and that was reflected in the growth that we saw there. In the third quarter, we had a lot of drilling going on, but we also had a lot of infrastructure expansion at that point in time. We knew we’d be adding that second rig, I think it came in, in August, and as a result of that, we had to expand, whether it was tanks or lines or gas lines or oil station lines so that we would have the ability to be able to transport the oil during bad months in the winter as opposed to dealing with trucking as much as possible. Eliminate those variables and then also the water handling systems that we had to expand. So a lot of the time, effort and money associated with the third quarter was spent on infrastructure expansion and the drilling with the expanded program that we put into play.

Very good. That was – lastly, how many wells do you say, remind me, with the two rigs that you or Danny say you can drill per year?

You drill about 5-plus. And so on a monthly basis, so you’re looking at about 60.

Our next question comes from the line of Jeff Grampp of Northland Capital Markets. Please proceed with your question.

Good morning guys. Was wondering, Tim, you made the comment on free cash flow profile kind of at a status quo. Was wondering how you think about potentially running the program like that, obviously, I know you can’t plan for acquisitions into model and things like that. But is that a program that you guys would actually look to implement? Or does continuing to accelerate activity levels seem like a more likely scenario? Just wondering how you kind of balance those two decision trees?

Yes, Jeff, I think really, the answer to that is this. At status quo, as you say, at current levels, that’s our plan. But we really anticipate that, as we get into next year, that we’re probably going to be a little more bullish on the commodity side. And so as we move along, and we see that advance, you shouldn’t be surprised if we were to accelerate, for example. And that’s why I was very careful to point that out a couple of times that, that was in the absence of a large acquisition or even an acceleration of the development plans. So to answer your question, that’s our plan right now. Our plan is, going forward, 2018 on into 2019, with two rigs. And we’re at the ready to add a third rig when we think it’s a good time to do so. So judgment will be something that will be weighed and we’ll make that ultimate determination.

Okay. Fair enough. And then I think Danny mentioned that, I think, it was double-digit sequential growth kind of a baseline for 4Q. Was just wondering, as you guys are kind of seeing things play out, if maybe 1Q 2018, may be more the quarter where we see more of the impact from the second rig in the dedicated frac crew and kind of playing some catch up there, just given kind of the lag time associated with getting these on and producing some of the water out in the early days. Directionally, am I thinking about that right?

Yes, you are. This is Danny. We will definitely see some increase towards the end of this quarter. But like I say, the frac crew just got here three weeks ago. And it takes us some time once they get through with their part, we’ve got to clean the wells out and then get them hung on and then it takes a little while for them to clean up. So I think you’ll see some impact as we move into the latter part of this quarter, but I do think the major impact will come in Q1.

Okay, great. Appreciate that. And thanks for time guys.

Thank you, Jeff.

Our next question comes from the line of Jason Wangler of Imperial Capital. Please proceed with your question.

Good morning everyone. Maybe just to kind of touch on Jeff’s question. As you get that completion crew in, you talk about the ability to get about 60 wells drilled a year. What do you think the cadence of the completion crew is going to be when you get it kind of up and running as far as timing to get completions done?

Good question. Danny?

Yes. Right now, we’re taking about – it’s about four days from move-in to completion to the next move-in. So it takes three days to frac and then it’s about half a day to move for each well. So we’re looking at about four days.

And you mentioned, I think, bringing a second crew in to kind of get you caught up, so to speak. I’m just curious where the inventory is now and where do you think a more normalized inventory would be for drilled wells as we look into 2018?

Right. So we typically – what we strive for, Jason, is to get a well on from the time rig leaves, we aim for about 30 days to get it on production – or to get it, yes, completed and hung on time. So when you factor that in, it looks like we’re probably going to end in the quarter with about 8-or-so wells that will be waiting on completion at that point.

And out of curiosity, where was that at, maybe at the peak before you got this crew coming in [indiscernible]?

We finished last quarter at 8. So it really wasn’t – so now that they’re here full time, and we’ve caught up a little bit, we’re looking now with two rigs, we’ll – just because of the timing, we’ll typically have about 8 wells at the end of each quarter waiting on a completion.

Well next question comes from the line of Mike Kelly of Seaport Global Securities.

Dovetailing on Jason’s question there, just do you have a good number for us what we would expect in terms of just completions in Q4 for you guys?

We should be looking at around 17.

Okay, okay, great. And was – am I right that you only had, was it five in Q3? That’s a pretty massive step up.

That’s correct. We did get five wells on in that timeframe and then, yes, it is, well, and it’s just the fact that we got a full-time dedicated crew at 100% up.

Okay. Okay, great. And just sticking maybe the completion cadence question too. We’ve seen a number of instances here from Permian players that have really kind of backtracked in their efficiencies, really on the completion side of things. Cycle times have increased, et cetera. And just wanted to get a sense of how you guys feel about this dedicated crew from Schlumberger that’s come in and kind of sticking with that, maybe 4-day program? Just how you feel on the efficiency front?

Mike, I don’t – this crew that we brought in, one thing I was telling Kelly earlier, is we’re very fortunate, we got a very experienced crew coming in. I know a lot of the operators have been mentioning issues that they have with new equipment coming in, having to work the bugs out. They’re getting inexperienced teams that they’re having to train up and it’s causing them a lot of problems. These guys, they came in and hit the ground running, and we’ve been extremely pleased with the equipment and the people. And I don’t really see that – our fracs are not that complicated and so it really – I don’t see that four days changing.

Yes, Mike, don’t forget, Mike, that these are really much shallower wells than what everyone’s used to reporting on. So we’ve got a much shallower depth we’re working with.

Okay, great. And just one more for me, and just looking at consensus expectations for 4Q. You gave the guidance of double-digit growth, not guidance, but there’s a lot of numbers that fall between – or incorporated in double-digit growth. And The Street’s at 5,700 a day for you, pretty aggressive ramp versus the third quarter. Is that something you’d think that is achievable in your mind? Or does that need to be pushed more into Q1 to see that sort of ramp? Understand if you don’t want to go there, but thought I’d try.

Danny, what are you – what do you feel comfortable with?

I think we’re going to have a nice number at the end of the quarter, I really feel like. But I do think you’re going to see the bulk of the growth show up in Q1.

So Mike, just to add to that, so as we’re tailing off the quarter, the fourth quarter, I think everyone is sensing here is that the impact is going to show up in the first quarter. It’ll be tailing in this quarter, but the results to the bottom line will come in the first quarter.

Our next question comes from the line of Steve Hosel with Strive Incorporated. Please proceed with your question.

Hi. I’m wondering what the joint venture is on the balance sheet and the income statement? And are you going to do any joint ventures because you have so much acreage?

Yes, that question probably relates to – and Randy, I’ll lean over to you. I think the gentleman might be making reference to the assets that were in Western Kansas. Is that what’s on the balance sheet, Randy?

I guess – is that the question you’re asking about?

His question was related to the JV, the joint venture.

Well, the joint venture, there’s nothing on our balance sheet. I guess I’m trying to – are you talking about joint interest billing? The joint interest billing is working interest partners that we have in properties. Unfortunately, we’re not always able to acquire 100% of the working interest in properties, but – so that’s their portion of those costs associated with drilling and so forth. Is that your question? Or you are referring to the derivatives?

I don’t know. I just wondered whether you were doing joint ventures. And that I saw it on the balance sheet and the income statement.

Let me take that, Randy, and maybe I can be helpful here. Sir, at one point in time early on, we have entered into a joint venture relationship on some assets that we owned and operated in Western Kansas. That joint venture has dissolved and, in fact, we no longer own the assets, so we dissolved the partnership or the joint venture relationship and the assets as well. And that really ceased to even be any part of our operations going back 1.5 year, maybe two years ago.

Okay. Thank you.

Thank you.

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

Hey good morning gentlemen.

Good morning.

I had some micro questions about cadence, most of them have been answered. So bigger picture question relative to cash on the balance sheet and acceleration in oil prices. Oil prices stay a little stronger, would you let cash build up for a period of time before you might accelerate? Or how should we think about that? And then how should we think about cash levels in terms of dry powder for an acquisition?

So David, at the current pace that we’re on and partially what we touched on earlier, at the current pace that we’re on, we see inventory or a build-up in cash beginning by the mid-part of 2019. That’s with the two rigs. But the real question is, and was asked from one of the listeners earlier, is do we – between now and then, do we consider accelerating or does that factor in acceleration? It does not factor in acceleration, it’s just the two rigs. But if we were to accelerate, and for good reason, then of course, that can change up a bit. But that’s just – we’re going to see how things move forward here. We’re certainly at the ready and, as Danny, I think, already touched on, infrastructure wise, staff wise, we’re ready to move forward and add to the rig count. But we’re going to wait, we’re going to be patient, we’re going to be able to add a very impressive growth over the next year. And as we go into 2019, if we’re still running at two rigs, we’re going to continue to grow. And then we will get to a point, we’ll cross over, and then we’ll be starting to build a surplus of cash. And by then, obviously, that third rig, if not already on-board, it will be very close to coming on-board.

Our next question comes the line of John White of Roth Capital.

I had a question about the science wells that Danny addressed that, so I appreciate that. And Danny, I’m glad to see you’re going to get some help, I know that you’ll look forward to that. Congratulations on the progress. Thanks again.

Our next question comes from the line of Joel Musante of Euro Pacific Capital. Please proceed with your question.

Hi, guys. Most of my questions have been answered. But I did have a question about your average net working interest for your wells going forward. And if What that would – what should we use or assume for that? And do we expect that to move around as you kind of develop your acreage?

Yes, that’s a good question, Joel. David, are you in a position where you can help Joel on that? Hello? Hello? I’m sorry, David, could you hear me with that question?

Yes, yes. We sure could.

We had some technical problems, sorry, Tim. David was saying that we were going to be around 70%.

Okay. And going forward, is that kind of a good number to model – use to model out?

I think it’s a safe number to work with for now. There’s obviously some areas as we move towards the Devon and things of that nature where we had higher net interest and we have higher ownership positions up there that, that number will go up considerably. And so just depending on where we are, but for now I think that’s probably a safe number to model with.

Okay. And just near term, I guess, if we’re talking about the 2017 wells in the fourth quarter, is that kind of where you’re at on those too?

Yes. You’re correct.

Joel, just an added comment on that. Think about it this way as well. So if we had 100% of the working interest, you’d see that at 75-plus, most likely. But because we don’t, and as Randy was touching on earlier, because we don’t always have 100%, maybe it’s 85% or 90% of the working interest, et cetera, that’s what’s going to bring it down to that average of that 70% NRI.

Okay. Well, are we talking about – the 70%, is that your working interest in the wells? Or is that the net revenue in there?

Yes. I think your initial question, was it not NRI?

No, it was for working interest.

Okay, so what’s our average working interest, David?

It’s going to be around 83% to 85%. Yes.

Okay. And like I asked before, is that kind of applicable to near-term wells and wells in the future as well?

It is. It is, and Joel, what I said a moment ago, it still holds true also. As you move up north, that number, too, is going to change. It’s going to go up.

Okay, great. Thanks a lot. I appreciate it.

You bet, Joel.

Our next question comes from the line of Mike Breard of Hodges Capital. Please proceed with your question.

Nice quarter. You haven’t said much about the Delaware Basin. Have you completed your studies of the Brushy Canyon? And when do you think you might get round to drilling a well there?

Mike, we have. Well, we’ve done quite a bit of work, I don’t know that we’re completely finished. But yes, we have enough information but we still feel very comfortable that there are some potential, 1, maybe two potential horizontal targets out there in the Brushy Canyon. As far as timing goes, that’s kind of in [indiscernible] hands as far as that goes. But I would say the only reason we’re not out there drilling them now is because results that we’re having on the Central Basin Platform. The results out there in the Delaware will be comparable, but we’ve got such a good thing going on there in the Central Basin Platform, we just haven’t diverted any resources over there yet.

Okay. And one last quick question. What was your production in the month of October? Do you have a number for that?

I don’t have it in front of me, Mike. It’s been posted – well, it won’t be posted at the railroad commission until the end of November, so it wouldn’t be public data right now.

Okay. Thank you.

Thank you.

[Operator Instructions] There are no further questions over the audio portion of the conference. I would now like to turn back the call over to management for closing remarks.

Very good. Thank you, operator. And we all want to thank you for taking the time, we know it’s very busy right, a lot of calls going on at this time of year. So once again, thanks for your support. And as most everybody knows, we have an open-door policy, so if you have any follow-up questions, feel free to reach us. Thank you. Have a good day.

This concludes today’s conference. Thank you for your participation. You may disconnect your lines at this time. Have a wonderful rest of your day.