Ring Energy, Inc. (REI) Q3 2018 Earnings Report, Transcript and Summary

Greetings, and welcome to the Ring Energy Inc Third Quarter and Nine Months 2018 Operations Update. 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, Tim Rochford, Chairman of the Board of Directors. Please go ahead.

Thank you, Dana, and welcome everyone to the third quarter and nine months 2018 financial and operations conference call. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call this morning is Kelly Hoffman, our CEO; David Fowler, our President, Danny Wilson, our Executive VP, Chief Operating Officer; Randy Broaddrick, our CFO; Hollie Lamb, VP of Engineering; and Bill Parsons, Head of Investor Relations. Today, we will cover the financials and operations for the third quarter and nine-months ended September 30, 2018. We will review our results and provide some insight as to our current progress so far in the fourth quarter. At the conclusion of the overview, we will open up the call for any questions you may have. At this time, I'm going to ask Randy Broaddrick to give us a review on 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, November 6th. 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 September 30, 2018, the company had oil and gas revenues of $32.7 million and net income of $5.7 million, as compared to revenues of $16.6 million and net income of $3.1 million in the third quarter of 2017. For the nine months ended September 30, 2018, the company had oil and gas revenues of $92.5 million and net income of $16.1 million as compared to revenues of $43.4 million and net income of $6.3 million in 2017. For the three months ended September 30, 2018, net income includes a realized loss on derivatives of $2.7 million, an unrealized loss on derivative of $567,000 and stock-based compensation of approximately $1 million, all pre-tax. For the three months ended September 30, 2017, net income includes an unrealized gain on derivatives of $66,000 and stock-based compensation expense of $960,000, again both pre-tax. Without these items, net income would have been $9.1 million and $3.7 million respectively for 2018 and 2017. For the nine months ended September 30, 2018, net income includes a realized loss on derivatives of $6.6 million, an unrealized loss on derivatives of $2.5 million, and stock-based compensation expense of $3.1 million, all pre-tax. For the nine months ended September 30, 2017, net income includes an unrealized gain on derivatives of $66,000 and stock-based compensation expense of $2.8 million, all pre-tax. Without these items, net income would have been $25.7 million and $8.1 million respectively for 2018 and 2017. For the three months ended September 30, 2018, our oil price received was $57 per barrel, an increase of 23% from 2017 and our gas price received was $3.76 per Mcf, a 20% increase from 2017. On a per BOE basis, the third quarter of 2018 price received was $54.32, an increase of 24% from May 2017 price. For the nine months ended September 30, 2018 our oil price received was $59.65 per barrel, an increase of 28% from 2017 and our gas price received was $3.42 per Mcf, an increase of 7% from 2017. On a per BOE basis, the nine month period ended September 30, 2018 price was $56.43, an increase of 28% from 2017. Production cost per BOE for the three months ended September 30, 2018 increased to $12 as compared to $11.20 in 2017. For the nine-month period, production cost per BOE increased to $11.98 as compared to $10.62 in 2017. Going forward, we anticipate our production cost per BOE to be around $12. 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 September 30, 2018 to $18.44 per BOE as compared to $12.97 per BOE for the same period in 2017. Our total DD&A per BOE increased for the nine months ended September 30, 2018 to $17.73 per BOE as compared to $14.04 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 125% for the three-month period and approximately 110% for the nine -month period as compared to 2017. These increases are the result of a combination of significantly higher production volumes and the increased depletion rate discussed above. Our overall general and administrative expense increased $835,000 for the three months ended September 30, 2018 as compared to the same period in 2017. And $1.9 million for the nine-month period ended, as compared to the nine-month in 2017. On a per BOE basis, this equates to a decreased from $6.23 in 2017 to $5.33 in 2018 for the three-month period and from $7.68 in 2017 to $5.76 in 2018 for the nine-month period. The increases in total were primarily the result of increases in compensation expenses as compared to the same periods in 2017. On a per BOE basis, these increases were more than offset by an increase in production volume. On a diluted basis, the income per share for the three-months ended September 30, 2018 was $0.09 as reported. Excluding the pre-tax charges of $2.7 million for realized loss on derivatives, $567,000 for unrealized loss on derivatives and $1 million non-cash charge for share-based compensation. This becomes net income of $0.15. This is compared to income per share of $0.06 as reported or $0.07 per share, excluding the $66,000 pre-tax unrealized gain on hedges and $960,000 non-cash charge for share-based compensation in 2017. On a diluted basis, the income per share for the nine-months ended September 30, 2018 was $0.27 as reported. Excluding the pre-tax charges of $6.6 million for realized loss on derivatives, $2.5 million for unrealized loss on derivatives, and $3.1 million non-cash charge for share-based compensation, this becomes net income of $0.42. This is compared to income per share of $0.12 as reported or $0.16 per share, excluding the $66,000 pre-tax unrealized gain on hedges and $2.8 million non-cash charge for share-based compensation. As of September 30, 2018, we had $17 million drawn on the $175 million borrowing base on our credit facility and had cash on hand of $3.8 million. We are working on our fall redetermination on our credit facility. While it is not finalized and working with the agent of a lead bank on our credit facility, we are confident that the borrowing base will remain unchanged. In fact, we believe that in the face of an acquisition, we could increase the borrowing base, if needed. For the three-months ended September 30, 2018, we had positive cash flow of approximately $19 million or $0.31 per diluted share compared to $10.3 million or $0.19 per diluted share for the same period in 2017. For the nine-months ended September 30, 2018, we had positive cash flow of approximately $55.5 million or $0.92 per diluted share compared to approximately $26.3 million or $0.51 per diluted share for the same period in 2017. With that, I will turn it back to Tim.

All right Randy. Thank you. Appreciate the info on the review. At this time, I'm going to ask Kelly Hoffman, our CEO to onboard and do the operations for the quarter.

Thank you, Tim, and thank you everyone for joining us. In the three months ended September 30, 2018, the company on its Central Basin Platform asset drilled 16 horizontal San Andres wells and we're in the process of drilling two more. Company also drilled two new horizontal wells on its North Gaines property and all wells drilled in the third quarter were one-mile long. In the third quarter, the company finished testing and filed initial potentials on 15 new horizontal San Andres wells, four wells which were drilled in the fourth quarter – I'm sorry in the first quarter of 2018; five of which were drilled in the second quarter of 2018; and six which were drilled in the third quarter of 2018. The average IP on the 15 wells tested in the third quarter 2018 was 435 barrels of oil equivalent per day, which is 103 BOE per thousand foot. This compares to 18 new horizontal wells, which the company finished testing in the second quarter of 2018 and had IPs of 440 BOE per day or again 103 BOE per thousand lateral foot. In addition, the company has 17 new horizontal wells which were in various stages of completion testing as of September 30, 2018. So, for the nine months ended September 30, 2018, the company has drilled 40 new horizontal San Andres wells in the Central Basin Platform asset. In addition, the company has drilled three new horizontal wells on our North Gaines Property and one new horizontal Brushy well on our Delaware Basin Property along with three saltwater disposal wells and we're continuing with the upgrading on the infrastructure also in all those areas. In the first nine months of 2018, we tested and filed IPs on 45 new horizontal wells and the average IP of the 45 wells was 437 BOE per day. Again, that was a 103 BOE per thousand feet. In the second and third quarters of 2018, the company performed workovers on 11 existing San Andres horizontal wells, because of an iron sulfide buildup in the wells. You might remember, we talked about that on some of our last calls even in some of our documentation and so the average cost of each of those workovers is about $350,000 and is based on a received price per BOE of $50, and expect payout on that investment at about four to six months. As a result, net production for the third quarter for 2018 was 600,000 – approximately 600,000 BOEs as compared to net production of 376,000 for the third quarter of 2017. That's an approximate 59.5% increase. And net production of 532,000 for the second quarter of 2018 and that's an approximate 12.8% increase. September 2018 average net daily production was approximately 7,294 BOEs as compared to net daily production of 4,345 BOEs in September of 2017. That's increase of 67.8% and net daily production of 6,605 barrels a day in June of 2018 and that's an approximate 10.4% increase. The average estimated price received per BOE in the third quarter of 2018 was $52. And for the nine months ended September 30, 2018 net production was approximately 1,639,000 BOEs as compared to 980,000 for the nine months ended September 30, 2017 and that's an approximate 67.2% increase. With that, I'm going to pass it over to Danny for an operations update. Danny, go ahead please.

All right, thanks Kelly, I appreciate it. I want to bring everybody up to date on work we've done since Q3. We announced in mid-September that we were adjusting our CapEx in our drilling program for the second half of the year. We announced that we were going to drill 30 wells in that period of time and just let everybody know we're on schedule to get our 30 well done and within budget. That was announced at that time. We announced – the only change to that announcement was at that point, we had announced that we were going to two North – two additional North Gaines wells in Q4 and that we were going to drill two Brushy Canyon wells on our North East acreage on our Delaware property, which would be up dip – or excuse me, down dip to our original well and hopefully are a little oilier than the first well. The only thing we've changed on that is we have drilled one North Gaines well and we are in the process now of actually drilling three Brushy Canyon wells. The change in that schedule is mostly due for two things. One was moving the drilling rig. After we finished the first North Gaines well, we moved the rig out to the Brushy Canyon [indiscernible] as everybody knows that Delaware right now is under an extreme amount of pressure on build out of highways, roads and everything else associated with that. We had a very difficult time. It took about four days to get the drilling rig moved and rather than trying to fight that battle again coming back, we decided to go ahead and just stay in drill extra Brushy Canyon well, while we were there. Just let you know, we have spudded our first well in the Northeast area and are in the process now drilling that well. Our plan is to then drill the second well in that Northeast area and then we going to drill in the traditional Brushy Canyon well backed down by the initial well in our Phoenix state area. So we – that's a different – reason for the change. The production on that first well in the Phoenix State 1H, when it came online, everybody remembers, it's about 130 barrels a day of oil and about 2.8 million gas. Hung on to that rate for quite a while, about 600 BOE per day. Current production is about 75 barrels of oil and 1.3 million to 1.4 million cubic feet of gas a day. So still hanging in there at about 300 BOE per day and it's pretty quiet right now. We have been – I think we announced in our October update that we are able to now sell gas in that area. We finished out our high pressure gas system. We are selling gas quite successfully. And so, we are moving forward there. As for North Gaines, we did drill our first well our – excuse me, our announced well for North Gaines, our Ellen B. Peters number 3H in the same area as our – if you remember, we drilled a horizontal science well up there that we completed with three or four different completion techniques. This well is up in that same area. The first well, the 4H, if you'll remember, came in at little over 400 barrels a day. Very happy with that well. It's continuing to hold up fairly well. We are seeing rates 120 to 150 barrels a day. We have shut it in for the last several weeks as we've completed the 3H, the offset well. We have started flow back on the number 3H, we're already seeing hydrocarbons and it's looking very promising right now. It's been on – it's only been flowing back for two days. But right now, everything looks very encouraged – encouraging and we have started the number 4H back up. Of course the fluid level came up and that will take us a little while to pump that back down. The Loki 2H which is the well we drilled in Q3 that's about five miles to the Southwest, we saw initial rates on that well of around a 150 barrels a day. We have scaled back the operations in that area just due to the fact that lack of infrastructure. We have no electrical and no disposal capacity down in that area. And rather than go through the expense of continuing to pay for a generator and haul 2,000 barrels of water a day while we were testing, we did scale that back. We do have it running, but at a much lower rate. It's still making 20 to 50 barrels a day and about 1,000 barrels of water, but we still have a very high fluid level in that well. And right now, we are compliant to continue at that rate until we get an infrastructure – excuse me, a saltwater disposal well drilled that we'll be able to accommodate the additional water that we need to turn that well back up and get it pumped down. Overall we're very pleased with the – with the results we're seeing in both areas. We're still very pleased with the results we're seeing in our core area down in Andrews and South Gaines and look forward to continuing that program as we move forward. And with that, I'm going to turn it over to David to discuss land and acquisition.

Thank you, Danny. Appreciate that. We've been pleasantly encouraged by the size and the frequency of deals that we're seeing for sale on the platform and on the Northwest shelf. These are larger acquisition opportunities with existing PDP and associated leasehold that's for sale by piggy-backed operators that are getting low number of funding commitments. Since Ring is the only public company actively drilling horizontal wells on the platform, many see us as a natural aggregator of these assets. As a result, we've had some good conversations and have worked diligently this past year with many of these groups and expect continue having discussions as we seek the right mix of assets that will complement our asset base along with the right deal structure that makes those assets – that asset purchase accretive to Ring. Over the past quarter we've netted up leasehold that's in the heart of our core area of Andrews that will now enable us to permit and get several more locations on the drilling schedule. Additionally, we are making good progress thus far in Q4 with some small acquisition leasehold adds that again, are in our core area on the platform and we're hopeful that some of our ongoing discussions will prove fruitful as we continue to search landscape for larger acquisitions. And with that, I'll turn it over to Tim for closing comments.

All right, David. Thank you. Thank you, everyone. Before I turn this back to the operator for some Q&A, I'd just like to make a comment on behalf of the Board of Directors regarding the recent public request from one of our stockholders for the company to initiate a stock repurchase plan. The plan requested a buyback of up to 19% of the company's outstanding stock, costing an estimated $100 million to $120 million, which of course would require not only the use of our cash flow but also borrowed funds from our senior credit facility. First and foremost, we always are going to listen to any comment or recommendations from our shareholders, but while the Board clearly sees the potential benefits of leverage buyback program for the company's stock, particularly at these current market prices, we also must consider whether such a program or other alternative would deliver the most value, both in the short term and of course in the long term. Currently, our credit facility will not allow us to initiate such a buyback without receiving a special waiver or an amendment. As you know, we've always focused on maintaining a strong balance sheet, increasing production, reducing our cost whenever and wherever possible. Becoming cash flow positive has always been and continues to be one of the most important goals and we believe our current company strategy to achieve that goal is in our best course of action at this time – is our best course of action at this time for our company and its shareholders. So wanted to get that out on the table. And with that, I'm going to turn it back over to Dana, our operator, and she's going to open it up for Q&A. Dana?

Thank you. [Operator Instructions] Our first question comes from the line of Neal Dingmann from SunTrust. Please proceed with your question.

Good morning, guys, thanks for all the details this morning. First question, Kelly, you guys have made significant progress, obviously, on production as judging by your September number that you threw out there on the release. After that, I guess my question would be for Danny, after all these updated wells you've done, could give an idea of your comfort level with your type curve, now that you've obviously progressed even beyond the last conference call and maybe just anything else you could say about the confidence around that type curve going forward?

You bet. No, that's a great question. We obviously just put that type curve out there. What we did and the way we develop that type curve is we went back, obviously, and looked at our historical production. The initial type curve we had was the one that was built pre – before we even started our drilling program and that was based on what we were seeing out there in the area at that time, which was a limited number of wells. So, as we were able to get some history on our wells, we looked at how we were doing compared to that. We could see we were a little under that and so we went in and adjusted our type curve. And again, what we did – not only is the curve historical, but it also is kind of a – it is a forward-looking curve. So what we did is, we went back and looked at the historical data and as was pointed out in the review back in late September, what we could speak to that obviously are early 2018 wells were underperforming the curve. But we did take those wells into account when we built the new type curve and the difference being is that now we have virtually finished drilling that area that was causing the depression in early 2018 and we've moved back into the core area. We're starting to see very strong well performance in the wells that we've drilled since the second quarter. Q3 looks very good; Q4 is looking strong. So what we did is, we took the historical data and we applied it to what we see as our inventory moving forward. And so, what you see is kind of a hybrid there. It takes into account historical data, but it also takes into account the areas that we plan to drill this year. So far, it appears that, for the first few months – excuse me, for the last two quarters, we're right on target with that type curve. So we feel very, very confident that that type curve is going to be very useful to us for the foreseeable future, at least.

Very good. Thanks for the details. And then one follow-up, just looking at kind of your slides, can you talk about, Kelly, maybe just from a broader picture where you all sit with delineation? Again, I think there was – you've obviously had early success more down the South and you've talked a little bit about couple of the Northern Gaines wells. I'm just wondering, for you or Danny, maybe just talk about that broader 70,000-plus acres in the platform, how you all think about having sort of knowledge of the delineation of the play? Thank you.

Thanks, Neil. Yes, you know, when we look at what's happening up in the Gaines County, one of the points I think we've – I may have said this in the past, not necessarily should have, but I did and that was with the early stages of Andrews County didn't really look any different than what we're seeing. I mean what's happening up here, there was enough data points to justify picking up the acreage that indicated to us that we could figure that out up there. As we've gone up there, we started drilling a larger gross and net footage of oil. We've got a lot of movable oil, we're excited about it. We just need to find the exact right formula, if you will, a recipe for getting it out most efficiently from a cost standpoint and also from a production standpoint. We like what we're seeing. It's definitely very commercial. In some ways it matches our curve and so we're excited about all the opportunity up there that we've got. There's a lot of plug-in pieces that we think that will be down in the Andrews County area and the initial core area also that we're going to be able to continue to add on to what we've gotten out. Dave has sort of touched on that a moment ago. And we feel the same thing about the Brushy. There is a lot more work to be done. But honestly, in very early stages of the work that we've got into an emerging concept that we've got both in Gaines and out in the Brushy. We're pretty excited about how far along we are. I really feel like, from a company standpoint, we may be a little further along in this process and even we were, in some ways, back in Andrews County four and five years ago.

Very good. Thank you.

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

Hey, good morning all. Wanted to ask on the infrastructure spend. Obviously this year, you had quite a bit as you built out the plan. As you kind of wrap up this year and even look at 2019, do you see that kind of being a similar type of spend or does that start to kind of dissipate a bit as you've kind of got what you need in place?

Jason, that's a great question. I appreciate that. We – obviously we did spend a large amount this year building out infrastructure. You know the plan right now that we have moving forward is really just kind of work out from the core areas, which should limit that amount of spend that we have on infrastructure. It always going to be there. Obviously as we build out, we need to extend our oil lines to collect oil to new areas. We obviously have to drill a few new disposal wells here and there to handle that, and also build out the gas lines. But the core is there and that was a big part of what our plan was this year. We spent probably six months, building a 14 mile gas line in our Andrews County area and because there was zero infrastructure for gas in our area that we'd started out drilling in our core CVP area. And so that's something we had to do. Everything now is just step out, it's just adding a little here, adding little there. Obviously – look, as we drill through this year, we're going to be looking at some new areas and we may have to step out a little farther, but I don't see – I certainly don't see the kind of infrastructure build out. It will not be nearly as robust as it was this year. We're going to have to build out a little bit of gas system on the north end of our Delaware property. We have no infrastructure up there. But it won't be anything like what we did this year.

Okay. And you mentioned, in the prepared remarks, about just getting the rig over to the Delaware was a bit of – just the half of what's coming home. As you look at getting wells completed there or just as you look at the two areas, what do you think, as you head into next year to kind of try and mitigate those dysfunctions or just simply you've got kind of plan for some headaches in a couple of dates of a move as opposed to kind of easier moves ahead. Is there anything you guys could be maybe doing to mitigate that or do you see any issues, as you look at filling rig or completion. Just in terms of on the ground, how you guys are – be able to kind of keep the progress of your program going?

Right. No, look, I don't think it's going to hold this up, Jason. We – the part of the issue is, as pointed out, there is – to get to Orla, which is the area where our properties are at in the Delaware Basin, there's four roads they're all two lane and you've got, with the amount of growth going on in that area, it's just a tremendous amount of traffic, and the highway department is doing everything they can and they're in the process now of building out passing lanes and areas like that. But what – in the meantime, what's happening is there is times of the day, in fact about 20 hours out of every day you're down to one lane and a pilot car and they only let wide loads to go through four hours a day. And so what we've done is we've started breaking the rig down. The way we finally got around the problem was we hold our side of the road basically and tore the rig down to smaller pieces and we were able to get a more normal sized trucks and go through without the issues associated with hauling a wide load. We've learned that lesson and we'll use that moving forward. I don't see that being a big problem as we go forward. It's just something we had to learn. Even the trucking company we hire to go out there and do that was surprised at the issues that they face. But I don't see it being a problem moving forward.

Okay. I like the ingenuity of break it down further. I appreciate it and I'll turn it back.

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

Good morning guys. Was curious to maybe break down your inventory a little bit more on the platform here. And when we look at, I think it's like Slide 14 on your most recent deck, the 800, 850 horizontal San Andres locations. Do you guys have a split maybe roughly of, what of those locations are in what you guys would kind of define as your core area or areas where you have infrastructure sufficiently built out versus maybe areas where you guys would look to – need to put in some infrastructure.

Hey Jeff, we have – we have infrastructure on the build out that we spend a lot of money on this year and last year, of course down in the Andrews area that's sufficient. I would say they probably used as much as two-thirds, three-fourths of the Andrews County acreage piece, which is about 30,000 acres. So we can reach that. And then to the extent that we need to expand onto that, sort of think of it as a spider if you will, add another leg onto that. As Danny was referencing, we don't have to – we don't have to go out and rebuild the main base area the trunk area from an electrical, saltwater disposal, gas or oil standpoint. So I think that's probably pretty good, because we're just now getting up in the Gaines and we've just got a small number of wells up there, we have a little bit of infrastructure up there between the wells. We are in the process of, I would say, taking advantage of some local relationships that we have there on a disposal standpoint that are going to be very beneficial to us. And will cut down on our cost that are needed to add a really big system up there to start with. But I think we're in pretty good shape up there for now. We – lot of that early outspend that we had in the first part of the year, obviously was out in Orla. It was associated with a gas and oil pipelines that we have out there. So our disposal system out there is very robust already. And so from that standpoint – and you might remember, we own a lot of surface out in the Reeves, Culberson County area. So we can sort of turn on a dime and we also have I think 10-plus permits in our hand out there along with, as I say, a very robust system. So I think, for the most part, we – I think we have that figured out, if you will. And that's 20,000 acres out in Delaware. So, we feel pretty good about it overall.

Okay, great. That's really helpful Kelly. And then sticking on the Delaware with the upcoming Brushy wells. Can you guys give us a sense maybe handicapping what kind of oil mix do you think comes on these down dip wells that you guys are going after. And then timeline wise, do you think we get results on your Jan ops update or you think that's maybe a little bit further into 2019 when you have some results to talk about there?

You know what – and we're waiting to see on that oil gas mix. We think it's going to be oil areas. We move down dip and move to the North. So it'll be interesting to see. I think probably as far as when we'll be ready. We're going to – we're in the process of drilling the first well. It will not be fracked until early December. We may have some very – that's just on the first well in the Northeast. So we may have some very preliminary information to share, but more than likely it will come probably in our end of year financials, which probably I think is March, some point like that. Look if we – you know there is obviously a chance we could make an interim report during that period of time, but may be very early report in January and then all three wells should be online by March and we should have some good information to share at that point.

Jeff, it's probably – it's probably going to be maybe appropriate timing too as we do our ops update probably mid to second or third week of January. Hopefully we can have some information to pass along then.

All right, great. Looking forward to it guys, thanks.

Our next question comes from the line of John White from Roth Capital Markets. Please proceed with your question.

Good morning everybody and thanks for taking my question. I wanted to just clarify or expand on what Danny said earlier about drilling in the fourth quarter of this year. All of that drilling on the – for the San Andres is occurring in what you term your core area?

Yeah, it was on the CBP horizontal, John. The wells are – we've got, we – I think we have one or two that are in the area that's a little heavy on the water, but the bulk of the properties, almost all the rest of them are in our core area. So we going to see very strong results from those wells. Again, we have the one well in North Gaines, which is just now coming online and then we'll have the Brushy Canyon well. So – but to your question about the CBP horizontal, 90% of those wells are going to be more in the core area.

Okay. And – so the North Gaines, the Ellen B Peters 4H, that well has been around a 120, 150 barrels a day for coming up 45 or so days, right.

That's correct. It's probably closer to about 150 barrels a day and it's probably in the 120 barrels a day range. 120 barrels a day, 130 barrels a day now.

A pretty flat production profile, are you choking that well back?

John, we are somewhat limited on how hard we can pull the well. We really don't have it pumped down all the way yet. And that's really strictly a function of right now we're having to haul that water off and when you're talking about that many truckloads of water coming in and out every day, it does somewhat hinder our production, but not significantly. I think if we were able to turn it all the way up, it probably would still be around a 150 barrels a day. And just so everybody will know too, I mean right now we have a disposal well roughly a mile away already permitted and they've started drilling in Q1. So hopefully we'll get into Q1, early Q2, the water hauling issues will go away and we'll be able to really crank these wells up.

Okay. And that's an excellent segue to my next question. The salt water disposal well you just mentioned, that's going to serve as the Loki 2H and the Peters 4H and the Peters 3H, right?

Yes, we're looking right now on the – you know the cost to lay a line to the Loki well. That's one of the things we're looking at right now. It will definitely be able to service all the Ellen Peters well and we have acreage – we have every section around that Ellen Peters area. And I think what you'll see, John, is you'll see us do something similar to what we did in Andrews County and that you'll see a fairly localized drilling program, while we get the – just the kind of the beginnings of the infrastructure build out. As we upgrade the electrical to be able to handle all the new wells that we plan to drill in that area over time, but – and then the disposal capacity and then we're also – we have an oil line that runs through the property. It's inactive right now, but we're talking to our pipeline company. Same company we sell to in Andrews County, Centurion. They have a line that runs right through the middle of the properties. We're talking to them about what it would take to get that line back on – put back into use. So we've got some work to do there. So what – you'll probably see a development plan very much like what we did in Andrew. You'll see us start in an area and then we'll work out from that expanding the infrastructure and – as we move along. So we don't really want to get into a – like I was telling Jason earlier, you know we don't want to get into the kind of the infrastructure build out that we had to do necessarily this year which if you jump around a lot, all of a sudden now you're building out four or five different infrastructures rather than just kind of starting with core area and working down. So I think that will be the development plan that you'll see from us moving forward.

Hey John, I want to add something to that too. Up in that area that we're talking about in Gaines, one of the benefits that we have is we anticipated, with early indications of what we might be running up against. So we did have conversations and negotiation with landowners in that area. So our disposal numbers in that area are going to start out considerably lower than where we started at Andrews. So we're in the $0.03, $0.05, $0.07 range up there, whereas in Andrews, we started out at $0.25 and had to work our way down.

Yes, that's a good plan. I appreciate that. I'd like to ask another question, if I can? what do you think the difference is between the Peters 4H and the Loki 2H. Was it different completion technique or was the rock different or you want to say?

You know, I would just say, look, when we cored the areas, they looked very similar. One thing I would like to point, obviously on the 4H, the original science test well, the 5H and then the Loki 2H. Those wells were all drilled with sleeves. We went in and obviously went in and did the completions just sleeve-by-sleeve. I wanted to point out that new well that we just did, the 3H was the first well we've done without sleeve, which is a tremendous cost savings to us. So, just want to point that out while we're – while we're talking about that area. But as to the rock, we cored both areas. The rock looks very similar. The Loki, that area is – it is five miles away and I think we've got to learn about the completion down in that area. We are seeing a little bit of difference in the production that it's coming back and we've kind of got some ideas on what we might do moving forward. But the rock looks good. We have a good oil column and we just – I think we have some things to learn in that Loki area. But overall we like what we see from the rock.

I really appreciate that I really – I didn't realize the five mile step out. Thanks for all the detail.

Our next question comes from the line of John Aschenbeck from Seaport Global Securities. Please proceed with your question.

Good morning, Tim, Kelly and team, and thank you for taking my questions. So for my first one, I was just hoping to get your thoughts, kind of higher-level thoughts if you will, on the longer-term outlook of the company and the choices you have to either pursue growth or continue to pursue growth or transition into a free cash flow generating state. So if you keep your current two rig pace production growth, I suppose we'll eventually begin to stabilize and eventually drop below the low-double digit growth target you have out there. But conversely, you also hit an inflection point where you start to generate free cash flow, which I know it's been a really important milestone that you guys have been – had been wanting to reach. So I understand that maybe some moving parts here, assuming what your game plan is next year, but just taken a high level view and assuming you do keep two horizontal rigs running in the CVP. For how many more quarters should we expect low double-digit sequential growth. And then with that, when do you see yourself kind of transitioning over to free cash flow neutrality then to a free cash flow positive state?

Good question? Kelly, do you want to address that and I'll add a little as well.

Sure. We are ran some sensitivities internally here and we were kind of looking at $50 oil and when we look at – I'm sorry $55 flat. It really puts us into the second quarter of 2020, probably like April-May timeframe. If you take that number from $55 to $57.50 you get in sort of the January, February-ish 2020 number for that free cash flow position, John. And then if you take it to $60, these are realized prices by the way, if you take it to $60, then you're looking at some time in the November-December range of '19.

John, I'd like to add as well. As you mentioned, we're staying on pace. We've had a lot of discussion about that of recent. We have, as you know – as everyone knows on the call we have yet to put out a formal CapEx, you can look forward to seeing that in the latter part of the year or just in early part of ' 19. But right now, there is no reason not to stay on the pace that we're on, and we're feeling very comfortable that we can continue, to your specific part of the question, as it relates to double-digit, low double-digit growth quarter-over-quarter for how many more. We think we can go well through '19 and well into '20. The question really comes to this and I think maybe that's lingering on your side maybe to ask is, at some point in time, do we consider yet a third rig. Only time will tell, is it well into next year before we determine that or is it into the early part of 2020? We're prepared for it. As everybody knows on this call, we have a great credit facility, $500 million with a $175 million borrowing base. And as Randy alleged that could even, if possibly, increase for the right reasons. So between cash flow and between the facility, we know that we're well equipped to reach those goals through '19 and on into early 2020. But we just believe a lot of that is still part of the learning curve, John, and there are going to be acquisitions along the way. There are going to be leasing programs along the way. And so that crystal ball is yet to really form, but we'll see as time goes on.

Okay, great. Yes, maybe kind of taking in there a little bit more as – if I just think about your ability to maintain consistent growth rate while also keeping activity levels flat seems like a pretty difficult feat. I'm just wondering, what's the higher level read there? Does that speak to the lower decline nature in a lot of these San Andres wells or just how are you able to achieve that?

I think Danny will fill that, but keep in mind we're talking about through '19 and on into 2020, kind of on that pace, but go ahead Danny.

No, John, when we look at our modeling using the new type curve, we can see that growth, we're able to maintain that growth rate through at least '19. We are seeing a flattening as we go though there, obviously the wells are flattening out, we're getting a very good base built under our existing production. So that's a very positive for us. In addition to that I don't want to say that we're selling – our gas production is increasing dramatically, but we have doubled our gas production over the last year as we build out that gas system. That's obviously production that we were not accounting for last year. So that gives us the ability to add that in and we'll continue to build that out. And let me just – before anybody gets too carried away with that, let me say, our gas production will still be less than 10% of our overall production. So it's not going to be significant, but it does help us add as we go along, that was revenue and production that was just being flared or was not captured. So that's a nice addition for us and obviously again, those costs are behind us for the most part. But now our modeling indicates that with a few Brushy Canyon wells scattered here and there, and with our – the drilling that we're going to do which would be more in our core area as we move forward, we'll be able to maintain that growth at least through '19.

Okay, got it. That's great detail, appreciate that. For my second one, and Tim, you kind of addressed this at the end of your prepared remarks, but was just hoping to get your expanded thoughts on the – on buybacks in general. So I guess – and I'm hoping you can entertain me on this front here, but absent the current bank restrictions, would just love to get your thoughts on how you view the attractiveness of buying back shares currently, and I guess if you did have that restriction, how you would weigh the option for buybacks against other alternatives such as directing cash into the drill bit, which could help you not only de-risk your acreage but also help you grow production? So, how you just weigh all those options?

Yes, and that's a great question, John, it really is. Listen, so everybody needs to know that when the suggestion or the ideas we're kicking around about the possibility of repurchase, we didn't handle that lightly, we took it seriously, and in fact we took it to the Board level and we had a serious discussion about it. And we pursued the idea, not because we'd made a decision to do it, but just pursuing the idea and started weighing that versus the other alternatives. We did learn very quickly that with our facility as it's structured today that we're prohibited from doing that. As I mentioned earlier, it would take an amendment or a waiver to do that. We're in the redetermination season right now and we didn't really want to disrupt any of that. So we just let it kind of move, let gravity take its own course. But to the other part of the question, if in fact we didn't have that restriction or we have that ability, that's something we would look at. Right now we think our stock is way underpriced. We think it should be much higher for all the reasons we've been discussing. Time will tell and we'll see what happens here as the market response to this news today and more news that will hopefully be coming before too long will help support and show the evidence that we in fact are back on track. But I got to tell you that even if we have the green light today to make that move, to commit that kind of capital, I think personally and I think most of us feel this way, it would be a mistake. If we have to take money away from the drill bit, send the rig home, possibly miss an opportunity for an acquisition, I think that would be – I think that would be a mistake in doing so. But I'm not – we're not closing that door. We're always going to be open to it. In fact we hope at some point in time that we will have the flexibility within our facility to make that decision, if we were to make that decision to have that available. But I can tell you right now that we believe that the best thing for this company is keeping that drill bit turning right, and keep adding where we can add, and we've got some good things working there. By the way, David touched on it a bit, but that's how we're feeling about it, John.

Okay, great. That was great detail, that's it from me. I appreciate the time. Thank you.

You bet.

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

Hey, good morning gentlemen. Three questions here. First, just given the September level of production, can you give any color relative to kind of holding that level higher or lower?

Danny?

I think for that month of September, if you look forward, I think we'll be able to sort of improve on that somewhat during the quarter. David our goal, as Tim's always pointed out is and we've all also pointed out, we'd like to see that low double-digit would net into 15% range is kind of what we shoot for. And I think there is – we have a good shot at increasing that number in December. If you're looking at just the exit rate, I think we'll have a good shot of getting that type of growth, and then I think as far as maintaining that, absolutely, I don't see any problem maintaining that number.

Okay. And then when you look out next year, is there any sort of lumpiness or seasonality that you could see in your production. I would assume it's pretty steady because you've been running two rigs pretty consistently, but didn't know if you'd see a slower growth in the first quarter or something like that. So do you expect any seasonality next year?

You know I think until we get to a certain size and I don't know what that size is and we're always going to have a little bit of lumpiness in these numbers. And some of that goes to – we never know what's going to happen with weather or anything like that. The drilling rigs are the most reliable part. Completions, as we've pointed out in the past, it will take us three rigs to keep our frac crew busy full time. So obviously from time to time, we let them go which creates some lumpiness. So you may see us go out there and complete anywhere from four to five, six, seven wells in a row, we may let the rig – let the frac crews go for two or three weeks and then we'll bring them back. So we will see some lumpiness in that. I do think as we get – get more of a critical mass as far as gross production goes, the lumpiness will even out over time, but we're still going to have a little bit up and down as we move forward, at least for a little while. And too, some of that's going depend on where we're drilling. As we go out to the Brushy and the wells are a little gassier, we'll see a little bump in gas production, I'm sure or – so it's just – there's still some things that could cause little bit lumpiness, but I do think you'll see it even out as time goes on.

And David, this is Kelly. As we're referencing that lumpiness, that's where we're giving that thought process of 10% to 15% and we've had some discussions obviously, you and I have too about some of the quarters that have been considerably larger than that. There is a possibility of that too along the way. It just depends largely on where the wells are being drilled and what's happening in that particular area and if it is a statistical play. But sometimes you can get into an area where you have a number of really fantastic wells in a row and if those are lumpy in their completion, you might have a spectacular quarter.

Understood. And then, I'll say a little bigger picture question back to acquisitions, could you give some color maybe on an absolute level of debt that you would be comfortable taking on or leverage metric of debt-to-EBITDA that go with that when you think about a larger deal?

David, this is Tim. We probably would feel comfortable 1.5 times to 2 times EBITDA. I think, depending on the climate at the time, what the capital markets, whether they are healthy or not. Certainly, if that were to happen today that would be the case. Really largely depend on our facility or increasing our facility to accommodate that. But there could always be a mix of capital markets along with our facility along the way, but we're – as you know we're debt averse. But we know that debt could be our friend and right now debt is our friend. It's far cheaper money that makes a whole lot more sense to be used in that facility not only for our development program, but to some extent, some acquisitions along the way. But we're never going to be – you're never going to see us going north of a number – something I gave a range 1.5 times to 2 times might see us go a little bit higher than that, but that's probably [indiscernible].

No, that's all helpful gentlemen, appreciate the time and the color.

Thank you, David.

Our next question comes from the line of Glenn Primack from Promus Holdings. Please proceed with your question.

Good morning. First, David and Kelly thanks for going on the road recently with SunTrust. That was really helpful in learning about your story. Most of my questions have been answered. I'm kind of a Brushy fan, like the infrastructure in place and that you're able to get some cash flow from the gas. My only comment will be just to the question beforehand, if you guys stick with your plan, live within your means, I think the stock is a gusher, right, because where the equity is at, your price is at today, you don't want to give that up on any type of transaction even though someone on the other side might love to own a part of it. That's it and thanks a lot and I appreciate the transparency on the call.

Thank you for your comments.

Our next question comes from the line of John White from Roth Capital Markets. Please proceed with your question.

Thank you. But my follow-up has been answered, and appreciate the time.

Thank you, John.

Thanks John.

Ladies and gentlemen, we have reached the end of the question and answer session. And I would like to turn the call back to management for closing remarks.

Thank you, Dana. And we want to thank everybody for joining us on the call today. We hope that we've been able to cover a lot of the questions and maybe some of the points that were kind of lingering out there hopefully have been cleared up. As you know, we have taken a very aggressive role as it relates to our investor relations going forward. And so Bill Parsons is always available and of course management would be as well. So have a good day and thank you again for joining us this morning.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.