Ring Energy, Inc. (REI) Q4 2018 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy 2018 Fourth Quarter and 12 months Financial and Operating Highlights 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'd now like to turn the conference over to your host, Tim Rochford, Chairman of the Board of Directors. Thank you. You may begin.

Thank you, Matt, and good morning. And welcome everybody and all listeners to our fourth quarter and 12 months 2018 Financial Operations Conference Call for Ring Energy. Again my name is Tim Rochford, I'm Chairman of the Board. Joining me on the call this morning is our CEO, Kelly Hoffman; our President, David Fowler; Randy Broaddrick, our Chief Financial Officer; Danny Wilson, Executive Vice President and Head of Operations. Also joining us this morning is Hollie Lamb, VP of Engineering. Today, we will cover the financials and operations for the fourth quarter and 12 months, ended 12/31/18. At the conclusion of our fourth quarter and 12 months '18 overview, we will discuss the acquisition announced yesterday of the assets the Company acquired from Wishbone Energy and their immediate impact to this Company. Also, management has posted a slide presentation detailing the acquisition on the Company's website. For those that may not know, it's www.ringenergy.com and it's under the tab, Investor section or Investor tab. After the acquisition discussion, an open call will take place, any questions you may have we'll be happy to answer. At this point, we're going to start off with Randy Broaddrick, our CFO and I'm going to ask Randy to give an overview of fourth quarter and year-end financials for last year. Randy?

Thank you, Tim. Before we begin, I would like to make a reference that any forward-looking statements, which may be made during this call are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued Tuesday, February 26th, 2019. If you do not have a copy of the release, one will be posted on the Company's website at www.ringenergy.com. Although it does not affect the BOE value shown, there was an error in the gas volume in our press release issued yesterday. The correct values are 302,890 Mcf for the fourth quarter and 1,112,177 Mcf for the 12-month period. Again, this does not affect any other values shown. Our audited financial statements will be filed as part of our annual report on Form 10-K, no later than this Friday, March 1st. For the three months ended December 31st, 2018; the company had oil and gas revenues of $27.6 million and a net loss of $7.1 million, as compared to revenues of $23.3 million and a net loss of $4.5 million in the fourth quarter of 2017. For the year ended December 31st, 2018, the company had revenues of $120.1 million and net income of $9 million as compared to revenues of $66.7 million and net income of $1.8 million for the same period of 2017. For the three month period of 2018, the net loss includes a pre-tax realized loss on hedges of $4.6 million, a pre-tax unrealized gain on hedges, unrealized at $6.4 million and a ceiling test write-down of $14.2 million. Without these items, net income would have been approximately $3.5 million. The three month period of 2017 net loss included a pre-tax unrealized loss on hedges of $4 million and an additional tax provision of just under $7 million. For the year-ended December 31, 2018, the net income includes a pre-tax realized loss on hedges of $4.6 million, a pre-tax unrealized gain on hedges of $6.4 million and a ceiling test write-down of $14.2 million. Without these items, net income would have been approximately $3.5 million. For the year ended 2017, net income included a pre-tax unrealized loss on hedges of $4 million and the same additional tax provision of just under $7 million noted for the fourth quarter. For the three months ended December 31, 2018, our oil price received was $48.65 per barrel, a decrease of 10% from 2017 and our gas price received was $2.05 per Mcf, a 39% decrease from 2017. On a per BOE basis, the fourth quarter 2018 price received was $45.55, a decrease of 12% from the 2017 price. For the year ended December 31st, 2018, our oil price received was $56.99 per barrel, an increase of 16% from 2017, and our gas price received was $3.05 per Mcf, a 6% decrease from 2017. On a per BOE basis, the price received during the year ended December 31, 2018 with $53.78, an increase of 16% from the 2017 price. Production cost per BOE for the three months ended December 31, 2018; increased to $13.76 as compared to $12.17 in 2017. For the year ended December 31, 2018; production costs increased to $12.45 per BOE as compared to $11.11 for the same period in 2017. Going forward, we anticipate our production cost per BOE, to be in the low to mid $12 range. Most production taxes are based on values of oil and gas sold, so our production tax expenses are directly correlated to the commodity prices received. Our production taxes as a percentage of revenues remained relatively flat and should continue to be. Our total DD&A or depreciation, depletion, and amortization including accretion of asset retirement obligation per BOE increased for the three months ended December 31, 2018 to $17.80 per BOE. As compared to $16.01 per BOE for the same period in 2017. For the year ended December 31, 2017 rate increased from $14.66 per BOE to $17.75 per BOE. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amount. As a total, the three-month period ended December 31, 2018 increased approximately 46% from the comparable period in 2017. For the year ended December 31, 2018, the total DD&A increased approximately 88%. 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 for G&A increased $486,000 for the three months ended December 31, 2018 and $2.4 million for the year ended December 31, 2018, as compared to the same periods in 2017. On a per BOE basis, this equates to a reduction from $6.51 in 2017 to $5.77 in 2018 for the three month periods and from $7.31 in 2017 to $5.76 in 2018 for the annual period. The increases in total were primarily the result of compensation-related expenses. The decreases in the per BOE rates for both the three and nine month and 12-month periods are primarily a result of increased production volume. On a diluted basis, the loss per share for the three months ended December 31, 2018 was $0.11 as reported. Excluding the $6.4 million pre-tax unrealized gain on hedges, the $14.2 million ceiling test write down and a $780,000 non-cash charge for share-based compensation, this loss becomes net income of $0.01. This is compared to a loss per share of $0.08 as reported, or $0.10 income per share for 2017, excluding the $4 million pre-tax unrealized loss on hedges and the additional tax provision of $7 million and a $922,000 non-cash charge for share-based compensation. For the year ended December 31, 2018, net income per share was $0.15 as reported excluding the $4 million pre-tax unrealized gain on hedges, the $14.2 million ceiling test write down and a $3.9 million non-cash charge for share-based compensation, this becomes income per share of $0.33. This is compared to income of $0.03 per share, as reported or $0.25 per share, excluding the $4 million pre-tax unrealized loss on hedges. The additional tax provision of $7 million and a $3.7 million non-cash charge for share-based compensation. As of December 31, 2018, we had $39.5 million drawn on the $175 million borrowing base on our credit facility and had cash on hand of $3.4 million. For the three months ended December 31, 2018 we had adjusted EBITDA of approximately $11 million or $0.18 per diluted share compared to approximately $14.6 million or $0.26 per diluted share for the same period in 2017. For the year ended December 31, 2018, we had adjusted EBITDA of approximately $66.5 million or $1.09 per diluted share compared to approximately $40.6 million or $0.77 per diluted share for the same period in 2017. With that, I will turn it back to Tim.

All right, Randy. Thank you for that overview. I'm going to now ask Kelly if you would mind Kelly just review the fourth quarter and 12 months operations please.

Thank you, Tim, and thank you everyone for joining the call today. So, in the three months ended December 31 2018, the Company drilled 12 new horizontal wells. The Company drilled eight San Andres wells on the Central Basin Platform asset, we had one San Andres well on our North Gaines Property and three Brushy Canyon wells in the Delaware Basin property and all the wells drilled in the fourth quarter were one mile long. In the fourth quarter, we drilled our, actually filed IPs on 12 new horizontal wells, the average IP on the 12 wells tested in the fourth quarter was approximately 414 barrels a day, and about 103 BOE per thousand foot, this compares to 15 horizontal wells, which we tested in the third quarter 2018, which had average IPs of 435 and again, we're also 100 BOE, 103 BOE per thousand foot. So for the 12 months ended December 31st, the company drilled 57 new horizontal wells, 49 San Andres wells on the CVP asset, three horizontal San Andres wells and one horizontal test well in the North Gaines property. We had four horizontal Brushy Canyon wells on our Delaware Basin property and for the 12 months ended December 31st, we filed IPs on 57 new horizontal wells and the average on the 57 wells was 432 BOE per day, and again, we're all 103 BOE per thousand foot. In the North Gaines area in the fourth quarter of 2018, we drilled one new horizontal well on that property with Ellen B. Peters 3H as the first horizontal well the company has used what we call a Plug and Perf completion method versus the Sliding Sleeve. We've talked about this in the past, but you might remember, refresh your memory here that the well was put on production in mid-November. We reached a peak rate of approximately 500 barrels of oil per day and it leveled off about 200 to 250 with a much higher oil cut in the gains here than what we were experiencing further South of about 30% to 40% of oil versus water. The water production on this well was substantially lower than the previous wells and that's what attributed to the change in the completion procedure that we had. So we're currently in the process of implementing additional infrastructure up there, and preparation of an ongoing drilling and development program in 2019. Moving on to the Delaware Basin asset, we have, we've got three new horizontal Brushy Canyon wells which we drilled in the fourth quarter of 2018, based on preliminary results experienced in the first Brushy horizontal well which was the Phoenix 1H that we drilled in the south western area of the property, two of the new wells were drilled in the North East, I'm going to elaborate on that here in a moment. As many of you might remember, we drilled and completed the First Brushy Canyon well, which again is the Phoenix 1H last May. That well was drilled very high on the structure, and IP-ed at about 130 barrels of oil and 2.8 million cubic feet of gas, we're currently producing the well, it's not being produced wide open as a matter of fact, it's, it has been choked back a little bit. We're still averaging about 200 BOE, somewhere around that range per day. We moved North and East on the structure, hoping to gain a little bit of an advantage there by moving down dip and getting a larger oil column. We put the Hugin 1H well in and the Hippogriff 4H well in an effort to hopefully find that larger oil column, we completed in mid-December the 1H, early production on that well, we have referenced at about 290 oil and about 500 cubic feet of gas a day. We've had some days, I'd just tell you that the oil production has been as much in a 24-hour period is double that in the 500 plus, maybe even 600 at times. We've had gas also as much as 700,000, 800,000 maybe 900,000 cubic feet a day. So, we're excited about what may be happening there. The Hippogriff, which is the second well that we put in that same area, we just got to pump in that well, maybe a couple of weeks ago, so it's still in the testing period, we're just getting it kicked off. We've since offset the Hugin well with a 2H, well, I guess it is, I'm going to have my number not exactly right, but that well is -- we just put the pump in it, I think the last week. So we expect some similar results out of that well and then we also have added another Phoenix well which would be called the 2H there as well and we expect production out of that to match with the 1H, it was doing. So just not to get you confused, we've got two Phoenix wells, we now have two Hugin wells and one Hippogriff well, all in the Brushy Canyon. So as a result, looking back in 2018, the fourth quarter including flared gas which is now being sold, BOE was approximately 628,800 as compared to net production of 422,000 BOEs for the fourth quarter of 2017, that's an increase of approximately 47.8%, a net production of 600,000 BOEs for the third quarter of 2018, and that's an increase of fourth quarter over the third quarter of about 4%. The December 2018 average net production including flared gas was approximately 7,099 BOEs, as compared to net daily production of 5,352 BOEs for December 2017, and that's about a 32.5% increase, and net daily production of 7,294 in September 2018, another 2.6% decrease. So for the 12 months ended December 31st, 2018, net production including flared gas was 2,262,800 BOEs per day, -- I'm sorry, BOEs total as compared to 1.402 BOEs for the 12 months ended December 31, 2017, -- that's 1,402 and it's an approximate 61.4% increase. With that, I'm going to hand it back to Danny Wilson here. And so, Danny can give you an update on operations. Danny?

Sure. Thank you, Kelly. Before we go into what we're currently doing at this time, I want to address a few issues and we've had some questions about one of those being the difference between sales as we reported for the quarter versus production, there's approximately a 30,000 BOE difference in that. Of that amount, about 17,000 BOE of that was associated with the flared gas and the reason we report that obviously is production is that it's going to show up on the -- it shows up on the state reports. So, we do have to go ahead and show that as production, even though it's not sold. So, that accounted for the largest portion of that. We also had an additional 2,000 to 3,000 barrels that were associated with landfill as we built out our oil system, and our oil gathering system. Obviously you have to fill up the tanks, you have to fill up the pipelines. So it is production, but it doesn't necessarily get to the sales point until a later date. And the remainder of the production was associated with an inventory built that we had there at the end of the year, did not mean that we weren't able to move the oil assisted for various reasons we had an inventory build just right there at the end of the year, that will be worked off over the next several months. The another question that we've had coming up is -- has to do with our differentials, moving forward, we do produce a sour crude and you know as they're buying those over the years, this last year we've seen differentials to WTI, WTS up to $16 per barrel, that's before we add on the transportation costs, which was very even though prices were climbing, our net price per barrel was not necessary climbing due to the differentials. That, very happy to report it as of the end of the year, we started seeing that differential shrink. January's differential was about $7.59, February's was $4.30, our March differential actually went positive at $0.04 and we were actually receiving or actually will be receiving a bit of a premium even to WTI on that. And that has to do, I think, mostly to do with the slowdown in the oil that we're bringing in from the Middle East, which is, is usually a sour heavier crude, and also with the sanctions on Venezuela, which has shut down a lot of that incoming high, or excuse me, the very low gravity high sulfur content oil, which has actually made our sour barrels very attractive right now as the refineries need to dilute down some of the very sweet crude that they get from the Midland and Delaware Basins. So we're excited about that. Looking forward, I looked on the strip moving forward for the year, the worst process all was about a $1.83 differential and that was in the September-August range. So, and I think those will shrink down as we move through the year. As far as current operations, we have, we have one rig moving, we're drilling right now. We announced earlier, or at the end of last year, early this year that we would be going to a one-rig program in an effort to reach free cash flow in the second half of this year. We did implement that, we laid down, we had two rigs running in December, we laid those two rigs down, mid, middle of the month as we kind of reached our budget year when we laid those down and we picked one rig back up in, on January 1, and that rig drilled four disposal wells, three in the Delaware Basin, due to, and those were drilled due to expiring permits that we did not think we were going to be able to renew. So, we decided to go ahead and incur that expense and get those wells drilled. Then, we drilled one more disposal well on our Central Basin Platform properties, and that was to accommodate the new production we anticipate from our acquisition, which we announced, the Carlyle acquisition at the, and then some additional acreage we picked up at the end of the year. So, right now we don't anticipate any further need at least on our existing properties for any wells, obviously, that could change, but at this time, we don't see any additional need for any more disposals. The other rig we picked back up on January 1 started drilling San Andres horizontal wells and we've so far to date we've drilled three; we are drilling our fourth at this time during that time period, we also drilled a Brushy Canyon well back out in the Delaware, based on the results we saw from the those first wells that we drilled up in the northeast part of our acreage, where we were very pleased with the results we were seeing on this, particularly on the Hugin 1H. Kelly mentioned that it's been doing very well and it is, we've had some days, on average, it's a little over 300 barrels a day, but we've had some days in the 500, 600 and 700 barrel range. The well just continues to get stronger as it pumps down, we're not quite sure where it's going to level out, but, and then we've seen days 900,000 to 1 million cubic feet of gas. So, based on those results, we did go ahead and go up and drill another well offsetting that one, the Hugin 2H. Another question that we've been getting is the difference, obviously I know a lot of you have looked at the acquisition package. And you have seen that January's production is quite a bit lower than what we announced for December. Some of that has to do with the completion rates, some of that has to do with laying the rigs down. When we laid the rigs down, I think we completed one or two more wells after we laid the rigs down in December and then we didn't do another completion until late January. So, we had a pretty good gap in there of time, when we did not have any new wells coming online. And the wells that we did have coming online, were the Brushy Canyon wells out in the Delaware, which take anywhere from 30 days to 60 days to 90 days to actually start cutting oil. So, all those kind of together caused us to have a drop in production early in the quarter. In no way, do we think that is going to affect our ability to reach our stated goal of 20% year-over-year gain.One month is not going to affect that and we're going to see continuous ramping of production as we move forward and the completion started to even out a little bit. And with that, I'm going to turn it back to Tim.

All right, Danny, thank you. Right, just before I turn this over to David, one thing I would like to add, that we announced in January that we were going to bring to the Street -- or by the end of January. We're going to bring to the Street an updated CapEx version. And so, as you can appreciate the reason why we haven't brought that CapEx to the Street or made it public is because of the acquisition. And as you can appreciate, this acquisition changes everything. So, I just wanted to get that comment in and now, I'm going to turn it to David and ask David to review not only our acquisition activity and leasing activity last year, but add anything more to that he'd like to. David on that same note.

All right, thank you very much Tim. We ended Q4 on a high note with an acquisition from Tesoro Energy, it was a Carlyle funded Company that consisted of about 4800 net acres and roughly about 70 barrels a day of production, but the acreage was strategically located in one of our core areas of Andrews County. This was a very impactful acreage to add as it's contiguous to our current leasehold and it offsets some of our best producing horizontal San Andres wells and adds over 50 high-quality drilling locations to our inventory. Making the acquisition even more impactful was a water disposal infrastructure that readily plugged in to Ring's existing disposal system, as well as oil and gas pipeline, as it's our takeaway capacity. And two others separate bolt-on transactions, we picked up an additional 550 net acres of leasehold that added nine high-quality locations again in one of our newer core areas, both of these transactions were added for less than 1000 acre and are significantly accretive on improved PV10 basis. In our Northern Gaines area, and this was just recently, we closed on an additional 5000 net acres that also included a deep disposal well, the leasehold is also contiguous to our existing Northern Gaines leases and directly offsets the area where we've drilled our best wells in that area. All of these transactions were greatly impactful due to their proximity to our best wells. And with yesterday's announcement of the Wishbone acquisition, we're really in a transformative 2019, and we're looking forward to what else that may continue on as we proceed into, throughout this year. And with that, I will turn it back to Tim for closing comments.

All right, thank you, David. Well, this concludes the company's portion of the 2018 fourth quarter and 12 months financial, operational review. What we're going to do now is we're going to open this up here in a moment, we're going to discuss the recent acquisition that some of the assets from Wishbone, which we did announce yesterday in a press release. One thing, I want to point out, if you do not have a copy of the release and/or if you haven't been able to go on the website, I would suggest to do so because here as we go forward, we're going to make reference to those slides. Once again, you can go on the company website www.ringenergy.com under the Investors Tab and that will allow you to follow along with some of the slides that we're going to do the focus on. So, with that I'm going to start off by turning this over to Kelly, and you can get us kicked off on this Kelly.

Thanks, Tim. And so let me reference just the beginning stages of this. We started looking at it back, I'm going to say summer of last year probably in around the August, July time when we became aware of the potential for the Wishbone idea to maybe come to market. We got very serious about it in November and then we were invited back to the final bid of group in January. So, we had our hands on deck through December and January, trying to understand the acquisition fully. When you go to the website, as Tim pointed out, you're going to see there's the Wishbone acquisition deck is there and Page number 3 or Slide number 3 is the one I'm referencing in particular right now. And so I'd just give you the summary highlights here. So, it's immediately accretive acquisition to us, a $300 million purchase price, which is $270 million, cash and $30 million common stock. Currently, our NAV per share is estimated at about $7.46 and that increases that pro forma Proved NAV per share to about $11.33, and that's a 52% increase. When we're thinking about this as it relates to the company and sort of the key point associated with our production reserves and EBITDA, it doubles our production, essentially doubles our proved reserves, it doubles our future EBITDA. And that's why we're saying it's immediately accretive, very accretive as time goes on. So, increases our perspective horizontal San Andres locations by 363. Our credit facility, we increased it from $500 million to $1 billion in the facility, borrowing base increased from $175 million to $425 million. We're closing, the closing funds associated are going to be drawn against the upsized credit facility, and consequently, while there is no capital markets required to fund the acquisition, we have a low projected leverage of, at that point in time, after the acquisition of 2.2 times by year-end 2019 and estimate about 1.5 times for 2020, and essentially this reassures the ability to future cash flow neutral positive in the second half of this year. So, we're really excited about that and I'm going to turn it over, at this point in time, Tim, I'm going to turn it back to you for a moment, so that we can get Danny involved and get a little more color on this.

You bet. Thank you for that. That's a great overview. Danny and Hollie, if you're fine picking up the slide presentation and highlight a few of those for us please.

Sure, Tim. Yes, I hope everybody has had a chance to at least pull this up on their computer or download this, the acquisition deck, if you haven't, one of the things that we're very happy about in this and you can reference Page 4, Slide 4 on that, is the proximity to our existing production. I mean, the new properties that we're picking up are only about 30 miles to 40 miles away from our existing, makes it very easy for us to get to from Midland, from a standpoint of personnel, really what we're looking at is picking up -- hopefully we can retain their field personnel who are familiar with the properties, in-house, we will be doing some additional hiring to accommodate the new properties, but not even though we're doubling production, we're not going to need to double staff by any means. So, I mean we're looking at maybe picking up a couple of engineers and some land and accounting people. But from the G&A standpoint, it should be very impactful for us, be able to lower that G&A. Moving on to Page 5, we talk about some of these points were covered by Kelly. But as far as the transaction overview, obviously, we do have $300 million price, the $270 million of this is cash and $30 million in common stock, effective date is November 1 of 2018, we expect to close by mid-April at the latest. We show net production for Wishbone at this time of approximately 6,000 BOE per day, very heavily weighted to the oil side. We have -- were we picking up just a little under 50,000 gross acres and a little over 37,000 net. Mostly contiguous, and another thing we are very happy with it. The properties are very compact and very contiguous. And so it's -- it makes it very easy to operate. It is exist -- it is close to existing San Andres production from the old fields there, the Brahaney and the Wasson fields were very prolific San Andres producers. But in addition to that, you have the other operators in the area who developed this play. We've bee watching this play developed since 2013-2014 time frame when it really got kicked off by Manzano and in Walsh, were the two main players that kicked that off. Manzano is the one that really proved that you could step out away from these existing fields up in this area and get good economic production. Those properties are since obviously been acquired by Steward who has done an extremely good job of developing those properties, identified some issues in early on with the scaling and such, which caused a lot of problems, and they were able to come in and do some work in there and really increase production just by cleaning up those wells, and then they also came up with the plans on how to prevent the scale moving forward from the beginning. So they've done an excellent job. And the other operator in the area, who is also really help prove this acreage up is Riley Permian, they've done a fantastic job also coming in and developing the property. What we really like about this property, what we find it very attractive is, we are sandwiched between those two players. So you have excellent properties from Steward, you have excellent properties from Riley, and this property just fits right in there between, in fact they share a lot of common acreage where they're non-ops, they're involved in some of our new wells that we will be obtaining, and then obviously, we are in quite a few of their well. So there is a lot of sharing of information, a lot of sharing of completion techniques and advances. It's just a really good fit for us and we admire all those operators and look forward to working with them. As Kelly mentioned, we do have potential of drilling 363 potential locations on this in addition to the wells that are already there. That's in the absence of increased density. I know Steward in particular is experimenting with increasing the well density, possibly up to seven or eight wells per section. We have a study done by Weingarten out of very well-known reservoir engineering firm out of Houston, which indicates the potential for eight wells per section. Some of that has to do with the thickness of the pay and the layering of the different light zones in there, and I'll let Hollie cover that a little bit more in the future as far as the reservoir. But anyway it's exciting, and our well count is strictly based on six wells per section. So there is potential down the road for additional sites in there. Another thing that made us very attractive to this was their infrastructure, which they, they've kind of followed the model that we follow is that, you're better off owning surface out there and having your disposal wells on your own surface, so you're not paying landowner fees. They have several very large blocks of acreage, they've drilled their own disposal wells, they've drilled their own water supply wells for our frac water and they've integrated all those together, so they can move those fluids around the field, and then they have their own frac ponds for fracking. So they've done an excellent job of building out the infrastructure. So that I'm hoping as we get into this, we'll find out that the need for us to do additional work is going to be very minimal. One of the other points, if you turn to Page 6, just a few highlights on that, that I'd like to point out, is that, we are anticipating the IRRs, ROIs to be as good or better than what we have in our existing acreage, really doesn't mean that wells are any better than ours, they are just different than what we already have, and I'll let Hollie go into that. The reservoir works a little bit different, which gives us a little different production profile. And so, but there will be at least as good or better than the ones that we already have. So we're very excited about that. We do have the potential for stacked pays in there. We have up to five potential San Andres zones in that. They're not all in the same area, but they do stack across the area where you have multiple zones. We do have, with the 363 locations, plus our existing wells that we have in Ring, it does give us a 22-year inventory of drilling with a two rig program. One of the things I mentioned and Hollie again will go into this, is that, it does help us to have a more consistent production ramp, more and more predictable. We have a high variability rate, obviously, as you all aware in our wells in the San Andres down south where we'll see IP rates of anywhere from 200 barrels a day, all the way up to 1,200 barrels a day with our average being in the 400 barrel range. We see the same type of IP in this area, maybe slightly elevated above that, but the key is, they have very, the fluctuation and the difference between the wells is much lower. Their beta is much lower than ours is when we're looking in our area. On average, they are still about the same, but there's not as much range in there on those IPs, which should help us to be able to have more consistent production. Turn to Page 7, and that really kind of references that we're talking about. You can look across that acreage area, and it covers a very large area there. We've got wells from Wishbone, we've got wells from Riley, Steward, Walsh, shown on this, and you can look down those IP rates and you see the lowest in there is 160, the highest is in the low 600s. So much more compressed range that they have, but at still very, very attractive rate. I just like to say it's right on par with what we already have. On Page 8, a little bit more on the infrastructures. I mentioned, they do have their own surface, they own approximately 1385 acres of surface, and mostly in three tracks spread across the acreage. They have 21 saltwater disposal wells, they have capacity of the 178,000 barrels a day. Their water costs for disposal is $0.04 per barrel, which is extremely attractive. They've drilled four water -- 15 excuse me, 15 water supply wells that can provide a total of 12,000 barrels of water a day as a group.And with that, that we can fill a frac pond probably in about couple of days with that.So it gives us a nice capacity to be able to fill that up and we don't have to buy water from our surface owners out there, like we do down on our South acreage. They do have five frac ponds that they've scattered around the acreage. It gives them good access to frac ponds. They own their own complete caliche pits, and people wonder why that's important is because it's very expensive to go buy caliche from other people. We use that for our road coverings, we use it for all the locations that we drill on, plus all the battery locations where the battery sit, so that's a very nice cost savings to us. We can do multi-pad drilling.And so we also have -- according to their notes, we have their 60% of the capacity is unused, which means we can go out and get third-party water to come in as a revenue stream for that, for our disposal. And with that I'm going to turn it over to Hollie and let her discuss the -- maybe a little bit about the reservoir characteristics but then also the -- their reserves.

Thank you, Danny. So as Danny had mentioned, this is equally as good reservoir as what we're seeing on Central Basin Platform. What's nice about this reservoir is the consistency we're seeing across it.The depositional environment here was flatter and more consistent across the acreage, that we're not seeing the huge variability that we do see in Andres. Overall, as Kelly mentioned, the purchase price is $300 million with approved reserve value of $582 million. Of that $582 million, almost $290 million of that is PDP, which is Proved, Developed and Producing properties. This gives us a wonderful base to start out with, with a great saving BOE of the comparable to what we're seeing.So we're seeing a double of our net daily production. Of the proved developed -- of the proved reserves, there's 66 horizontal plays that are bookable at SEC standards, which gives us a lot of room for growth. And that is at the downspace fixed wells protection as Danny had mentioned. There are operators due to the thickness of the San Andres and the identifiable benches that they're seeing as they develop north to south and east to west, that they feel like they can go up to eight wells. So there is definitely a lot of meat left on the bone. The meat as well. If you look at the prospective locations, the 363 as mentioned earlier, that gives us a lot of running room and is a contiguous acreage block that allows for very strategic development throughout. If you switch to Page 10, this page really highlights why this deal makes sense. We more than increased our net acreage by 49%. Our proved reserves are up by 94%, our proved developed reserves, which is the PDP and PDNP is up by 58%, our proved PV-10 is a little over $1 billion, which is up a 107%, we doubled our current production and we are seeing a our huge increase in our prospective locations, giving us a long drilling inventory and some consistency, additionally to all of this obviously, it's going to help take out that lumpiness that we're seeing in production due to frac availability, drilling and so this is going to be accretive quarter-over-quarter. At this point, I'm going to go ahead and hand it back to Tim to talk about the accretive nest as far as the matrix per share.

All right, Hollie. Thank you. Yeah, everyone and again, if you're able to view this or you have it in front of you, if you could turn over to Slide 11, Page 10, as Hollie mentioned now, this is a slide that we've really kind of highlighted, what this really means on an accretive value on a per share basis. So just kind of starting at the top with net production, we're doubling the production as we've mentioned over and over again here. What that really means is, as you drop down and you can see in donut graph that we've provided that on a per share basis prior to this acquisition, we were about 96 barrels of oil per day on a per share basis, this jumps us to 177 or an 84% increase, as we go over to the acres, same thing again, we go from 76 a change to 37 a change that we acquire for a total of 113-plus, if you're looking that on a per share basis, we go from 1,202, now 1,660, that's a 38% increase. As you look at the perspective locations that Hollie pointed out and I might add, and I think Hollie and Danny and everybody would agree with this is that this isn't a go-patch drill out there. This is a quality area and although they don't fall on categories of total proved, or probables of possibles, they are really, really high level opportunities for prospective locations. We go from 882 to 1,245, that's 14, for 14 locations per share stand-alone, when you add the acquisition, it jumps to 18, 31% increase. And lastly on a proved basis on a PV-10 basis, we go from 542, we add the 582, we've got $1,123 million that Hollie mentioned, when you factor in the dilution, the additional approximate 5 million shares plus or minus, our proved PV-10 goes from $8.57 a share to $16.46 a share. I will point that out, that there is no debt adjustment there, we'll actually cover that on the next slide. So with that, bear with me and go over to Slide 12 or Page 12 and here's a pro forma net asset value that you can take a look at. So you can see that starting with Ring, we have $542 million in a proved only P1 category, $542 million, you look at Wishbone at $582 million, you look at our pro forma combined of $1,123 million, so we can go from, and this is with the debt adjusted. So we go from $7.46 on a proved NAV basis per share yesterday to a gain of 52% or $11.33 per share today, factored in the debt along with that. So I guess, bottom-line is, if you like this, yesterday, yes, I think you're pretty much at the lowest today. So with that, I'm going to turn this back to Danny for any closing thoughts that he may have that relates to operations and then you can give it back to be me, Danny.

You bet, Tim. This acquisition does a tremendous amount of things for us to predict, especially from a predictability standpoint, and this is one thing I've shared with Tim and Kelly and the Board as we have move through this process is what it really does is it allows us to get control of our completion right, drilling right. Dropping to one rig obviously present some issues as we have mentioned before, we’re our flat crew actually spends more time away from as now than it does with us and by bringing that second rig back in and getting up here on this acreage, we now get our -- basically control of that frac crew back, we can start doing multiple completions at a time, instead of just doing one-offs as we move through with one rig. And so, it really brings us some tremendous opportunity to level things out. We don't have to add a lot of staff, which I think is going to be very is going to be very good for us, and I'd say that because it's the same animal we're dealing with right now. We don't have to bring in another crew that has to understand the whole new reservoir, a new completion techniques or anything else. So it's just a tremendous bolt-on, really almost a bolt-on for us and we're looking forward to working on this project ourselves, but also with the other operators in the area. I think, we've all got a lot to learn together and I think through that, we'll see some tremendous progress in this area. With that, I'll turn it back to you, Tim.

All right, thank you, Danny thanks everybody, good job. So before turning this back to the operator, I'd like to make this closing comment. As you can imagine, we at Ring over the years we've looked and evaluated multiple opportunities and over those years, there's no question, they could have brought potentially lots of value, enhance the value, the ultimate value that Company could have grown and a lot of those deals were very attractive, but I can tell you and I can tell you this without hesitation, this is the best that we've seen. And I know that everyone that's worked on this feels the same way. So we're going to go the operator in a moment, but there's no doubt about -- that this is a major game changer for Ring Energy and its shareholders. So with that, this concludes our overview of not only the operations and financial side, but also the review of the acquisition. I'm going to turn it back over to you, Matt, and ask you to go ahead and open it up for questions that we may have.

[Operator instructions] Our first question is from Jason Wangler from Imperial Capital. Please go ahead.

Hi, good morning, everyone. Congrats on the deal. Wanted to ask, as you look at kind of I think you talked just now about the completion crew, but also kind of how you think about -- how you'll attack this from there together, I assume you run two rigs, will be one on each of the properties, the legacy ring, one on Wishbone or how do you see that kind of going forward.

Yes, good question, Jason. Danny, you want to take that?

You bet, no, Jason you're exactly right. That is the plan moving forward is we'll have one rig Ring on the existing properties, drilling our core area, and then we'll have the second rig out there working with on the new Wishbone acreage. So, and as I mentioned, you know, now, it really takes about three rigs to keep that frac crew busy, so we're moving toward that, there, I guess at some point there will be a possibility that we will pick a third rig up, but I don't think we're looking at that this year, but potentially next year, which would put that frac crew working for us full time without going anywhere else. So we're looking forward to that.

Sure, I appreciate that. And then maybe just from the financial side of it obviously the credit facility, higher, Tim, you guys have always been pretty debt averse [indiscernible] obviously picked that opportunity. But how do you think about it in terms of just keeping that debt on the credit facility, and then also how do you think about maybe changing of the hedge strategies going forward with the asset leverage.

Yes, you bet, Jason. Two good points. Let me just before I address those if I may to go back to the conversation, you were having that Danny was responding to, one thing that again I know we mentioned it earlier in the call, but I want to say it again, that by the time we close this, which is anticipated sometime on or before the kind of the middle of April, we will come with a formal CapEx. And Jason, assuming everything is timely as we've outlined and most I think in all probability, and Danny you tell me if we're wrong about our thinking on this, but does the rig and on the Wishbone assets will probably be redeployed about mid-May or so. Does that sound right, Danny?

That's correct.

Good. Okay. All right. Jason, so to your point, or to your questions, as it relates to the leverage and how we think about the debt and eventually capital markets, for those of us that have known us for a long time, you know that we haven't been afraid to take a kind of a disciplined role in managing our balance sheet by going with capital markets from time to time. Obviously, under current conditions, that's not something that's even contemplated right now. As far as the debt is concerned, we have, we don't have any doubt, we don't have any second thoughts at all that we can manage this debt. I think as Kelly touched on earlier in some of the points on the acquisition that, as the first year, the year '19, we kind of look at somewhere about two times the EBITDA ratio. And I think we've seen that managed down to about 1.5 or 1.5 times for 2020. I will add to that, Jason, that if capital markets improve or when they improve, not yet, but probably not very optimistic on that, but when they do improve we'll consider that, we'll look out things are going. As Danny mentioned, I think that there isn't any question that we are going to feel very comfortable about reaching our cash flow neutral, cash flow positive as we go into second half of this year, particularly, as we started adding surplus of that capital, we start looking at year-end, and rolling into '20 with the possibility of adding another rig or possibility of maybe even further consolidation. There's no question in that, that the move to acquire these assets from Wishbone was significant at many levels, not just all the points that we just brought out, but it really sets the stage for Ring to become the consolidator. And so, as we go forward, whether it's capital markets combined along with our borrowing abilities, we're going to look at all those opportunities. And I will, if you don't mind, Jason, I'm just going to add one more thing that if you look back on how we've managed our balance sheet. And I know we've had a lot of people that have supported the way we've managed the balance sheet, we've even have some mild criticism, but I just wanted to show as an example, last year, about a year ago right now, we raised equity. We raised capital somewhere in the $80 million range. If we had not done that and we would have started using in borrowing the drawing down on our credit facility. There isn't any question by the time we reach the summer and the fall, that facility was probably reaching something much greater, maybe in the neighborhood of $75 million to $100 million, particularly with a couple of these acquisitions of leases that we had. We would have really minimized our opportunity for this acquisition or even possibly other ideas. So I don't think there's any question. There were multiple -- multiple buyers. There were multiple ideas coming to the table on the Wishbone assets. And I believe this certainly as we were having this conversation right now, the reason why we got that deal is because we had a balance sheet to get it done. And I know that Quantum had the confidence in our ability to get this done. So again, what we've done in the past from a management standpoint on the balance sheet and how we're going to manage it going forward, I think you can have a lot of confidence that we're going to be following the same discipline and we'll be on top of it, Jason.

I appreciate all the color.

Our next question is from Neal Dingmann from SunTrust Robinson Humphrey. Please go ahead.

Good morning guys, thanks for the details today. Kelly, my question is a bit on guidance. I think you all have previously said around 20% growth generally around per rig. Is this still the case, and I guess, it's tough to think about, as the rig doesn't come out until May?Is that still the case whether you run one rig, two rigs, maybe you could just talk about in broad terms how you think about the guidance there for, Kelly for you or Tim?

Sure. Absolutely that growth rate that we were giving guidance on to 20% was related to one rig, and one rig will do that. So we're very comfortable with that. Obviously, if you add the second rig on, depending on how the wells come on, it could be as much as double, it could be more than that. So what we're going to have to do is get that system up and running.And as we've mentioned, we're dedicated to doing that in short order.

Neal, I'll comment as well. And I support exactly what Kelly just said. Looking at the likelihood that we have that rig in mid-May, things don't always come across on time. So, but, if we're up and going on the Wishbone assets, certainly by the latter part of the first half or certainly by mid-year. I think it's very likely that we can do the math behind that and see what that's going to contribute toward the growth percentage. So I think that it's very likely as it's going to certainly exceed the 20%, whether it exceeds 30% or more, we'll just have to wait and see how things kind of come together from a timing standpoint. But I can tell you, equally as important, Neal, is the -- is our goal, our top priority of goal to get to cash flow neutral and cash flow positive.And I think that this acquisition goes a long ways to ensure that. And so I think that kind of -- I think timeliness of that along with the add of the second rig as we go into the second half of this year, will determine that cash flow positive and/or neutral along with the growth factor as well.

That was going to be my follow-up, Tim. I think it's on Slide 6, you mentioned that about maintaining a projection of free cash flow by the second half. I guess, is that still the case regardless of whether you bring in that second rig or not?And I guess that's kind of the first question on the free cash flow, and second around the free cash flow. The thought about it, Danny made the comment about -- you can keep -- better keep a full time frac spread if you add a third. It seems to me that would even add to more capital efficiencies. So I guess just for any well that you could comment on the free cash flow. I mean, does it improve when you bring in that second rig? Again obviously, it doesn't instantaneously improve, but on a few months down the road, would it improve or how do you think about, I guess, outside of just decreasing that the acquisition brings, how do you think about sort of the sensitivities around free cash flow once the deal is closed, whether you bring in a second rig or third rig?

Yes. And again, the deal closes, let's say early to mid-April. As Kelly mentioned, we took the effective date of this, I think maybe Danny mentioned this November 1st, or from an operational standpoint, we're going to get some, we're going to get some leverage out of that by, as we wrap up the first quarter. So in terms of the growth that's going to contribute to the production side. As it relates to the cash flow, I mean almost instantly it's positive cash flow, Neal, until we add that second rig, and then you've got just a bump, you got a little bit of a lag there, and then it comes, it turns around again. I think if I'm understanding your question correctly, is it going to be accretive is going to make sense for us, once we see we cross that threshold from cash flow neutral to positive, also we bring in that third rig and how accretive that will be, and I don't think there's any question. We've got some learning and we've got some feel of way a little bit here, but that's what we're all thinking as well.

Okay. And then if I could just sneak one more in. Does this change, I guess, maybe a question for Danny, you definitely were having success in the Brushy, some of those areas about what you may or may not do thereby having this acquisition or really doesn't change anything in that regards?

No, no, it doesn't, Neal. We've really liked the Brushy. We think it returns over there going to be comparable to what we're seeing over in the San Andres horizontal. And we may occasionally go over there. I know internally, we've discussed maybe doing one Brushy Canyon well per quarter, and developing that out at a slower rate. The nice thing over there is everything is HBPed, we're under no pressure to get over there and drill it up or lose acreage. And obviously, the stuff in the San Andres does have time frames on it, and so it's going to be a little more time sensitive as far as getting those drilled. But we do love the Brushy, we think it's going to be a tremendous project for us. It's just hard to take a rig away and go over there and do that, that doesn't mean we may adhoc a rig every once a while, and go drill one, pick a third rig for a well and drill a Brushy, but that's something we'll discuss as we're building out our CapEx.

Our next question is from Jeff Grampp from Northland Capital Markets. Please go ahead.

Good morning guys. Just maybe a clarification on kind of potential rig cadence and that sort of thing prior to close, is this, is Wishbone just in kind of PDP decline mode right now, and then that will just kind of be a purchase price adjustment and at close, maybe it's something less than six or Wishbone operating a rig right now. And then did we hear you right, the base case plan is basically, we should think about back half of '19 Ring is running two rigs, just want to make sure, is all that, is all that kind of accurate?

Yes, I'm going to take the first half and then I'll let Danny or Kelly respond to the second part on that, Jeff. Yes, there is, there will be an adjustment to the purchase price, not based on the production profile, but based on obviously accumulated cash or cash surplus as we go along, as it relates to the second half of that question, go ahead Danny or Kelly, whichever.

Yes, and Jeff, just to point out is, yes, they, Wishbone stopped drilling in the third quarter as they were putting this well up for, this package up for bid. They did drilled at a pretty rapid rate until the third quarter. From there on they were concentrating on getting the wells they had drill completed, and so they really -- there hasn't been any new well adds for that property since, probably late November. So December, January, are just kind of, are kind of cruise control, there is not a rig running out there at this time. It's possible, we'll see a slight dip before we get the rig out there running, but again, those wells have a little different profile -- production profile where they tend to stay flatter earlier in their life, but there is a possibility, since there's going to be such a gap from -- say late third quarter till middle of the second quarter when we get the rig back up and running. There will be a little fall off, but then we think we'll pick it right back up pretty quickly.

Okay, great, that's really helpful. And for my follow up, I guess, when you guys, kind of, take a step back and think about, kind of, the new Ring Energy, maybe for Kelly or Tim, what do you think this story is when we kind of look into 2020 and beyond? Do you guys think you're to the point now where you want to generate some free cash and maybe there is a return of capital to shareholders or is this kind of a growth within free cash flow or just generically how you kind of view since you're doubling your production base and getting some more inventory? What -- how should investors think about the new Ring Energy?

You know, Jeff, I think that -- This is Tim. I think there is any question to the point of free cash flow, that's our main objective, as it relates to return to the shareholder, I don't think it gets any better than to turn those dollars around and putting it back to the ground as it relates to value return and ultimately a cash return for those shareholders. So that's what we're going to be focused on, we're not changing the format any as it relates to just look -- keep our eyes forward, keep drilling and that's to say that there's not other opportunities on the acquisition side, I do believe and as I mentioned earlier, we've become a consolidator, and I think there will be other assets that we'll see along the way or opportunities or ideas that we will see along the way that we'll explore that could also continue to help this new Ring, if you will, just become that much bigger.

Our next question is from John Aschenbeck from Seaport Global. Please got ahead.

Good morning, everyone. Thanks for all of the details and taking my questions. So, for my first one, Tim or Kelly or really anybody on the team there, I would just love to get your thoughts on how you weigh the merits of acquiring the Wishbone assets as opposed to potentially buying back your own shares? Just looking at the merits of the acquisition, I get to an implied valuation on a dollar per acre basis to a dollar per location basis, that isn't too dissimilar to the valuation applied by your current stock price, both about $2,000 of acre or $200 to $300 per location, I guess, depending on how you value the PDPs. So just with that in mind, curious is the -- is the real value proposition of this acquisition as opposed to buying your own shares, is it simply increased scale or are there perhaps some other ways to unlock value with this deal that maybe aren't yet reflected in your estimates? Thanks.

Yeah, I think that's a two-part answer as well, John, and thank you for that question. This is Tim. I don't think there's any question as time goes on, the unlocked value and I think, Hollie touched on it earlier with the remaining locations that are perspective here for the Company and I know, Danny touched on as well. There is a lot of value under the covers. No question about that. They're going to be unlocked. As it relates to on a buyback basis look, yes, and we would have, and we considered and there were some people that have some good ideas, that they threw on the table for us to consider buying back our shares back in the fall as you know. Had we done that, we would have been locked out of this deal. There isn't any question about that. And if you, if you come at it from a different direction, what we've really done is we've just bought an equal to our Company at a PDP basis, okay, we bought this just a small fraction under PDP. And I don't think, that there's any question that at the end of the day, as we start moving forward on developing that asset and seeing, the Company's seeing a realizing the value on top of that PDP is going to be much, much bigger and better for the shareholders as compared to the possibility of going back and purchasing those shares out of the market and using the gun as a dry powder for that. So I hope that answers your question, but that's the way how I look at it, and if Kelly has a comment on that, go ahead, Kelly.

No. I'm good Tim is well said, that's exactly the case.

Okay, great. Yes, I appreciate all the color there. Maybe, just following up on that, one of the ways to unlock additional value perhaps that caught my attention was Wishbone surface ownership and water infrastructure, which you guys kind of touched on briefly in your prepared remarks, but just, particularly the water infrastructure, there's quite a bit of capacity there and a lot of it un-utilized at this point. So I'd just love to get your thoughts on your overall strategy for that asset, and do you think it could be used in the future as an asset divestiture candidate, once you fill up that capacity and it starts generating more cash flow. Thanks.

You know, John, that is really an excellent point. In fact, you can even broaden that question by saying, okay, is the, the unlocked value is that, is that something that we consider doing at some point in time, that would allow us to raise capital, rather than borrowing or even doing with the capital markets. Not only think about that, but think about Delaware, think about lower or the south at the platform. We have now three systems, SWD systems and everybody on this call pretty much is familiar with how those kinds of assets have been trading lately in the demand form. So we recognize that there is underlying value there in all of those areas. First and foremost, we have to take care of our operations to make sure that we adequately have room and space to take care of our own. Beyond that, there is certainly the opportunity to add an income stream line on it, no doubt about that. And then there is lastly, the possibility of monetizing as you say. Once these are reach capacity or close to it, that could make some real sense. But we'll just wait and see, but believe me, we've looked at that very closely, John.

Great, Tim. Appreciate it. And one more if I could sneak it in. Just wanted to follow-up just on the overall proof of concept on the Wishbone asset. I'm just, I guess, looking at your acreage map on Slide 5 and comparing it to the existing horizontal wellbores, many of those existing wellbores in between your larger acreage blocks in the Yoakum County, but many of those on the periphery of your Yoakum County acreage as you move north and south, and then very little data points in Lea County. So I just love to get a feel for your overall confidence and the San Andres' proof of concept here at least in terms of horizontal play across the entirety of your 37,000 net acres, and then maybe you could share with us a little bit of the supporting detail or data points that you have internally, that gives you that confidence. Thanks.

Yes. That's a good question. Danny, Hollie, can you guys take that, please?

Yes. No, John we've looked at this from a geologic standpoint and there's -- and it's been studied by all the operators out there. And I mean, we've seen data all across this area, and we do feel like the reservoir rock is good throughout the acreage.We've seen, obviously, you do see the concentration there in the middle and that's where Manzano started to play in Walsh. So obviously that has got the highest concentration. But we've also looked at the wells with Riley, we've looked at the new wells that Steward is drilling. And we are seeing impressive results. I mean, the results are still very good. Wishbone obviously, they started out close to where everybody else was already at Riley, Wishbone and Steward. And so they've worked out from there. But we're seeing good results all the way through this. As far as the acreage in New Mexico goes, in particular, the one up there to the Northeast -- or excuse me, Northwest there, that's an acreage that's jointly owned with Manzano. And I think the first well in that area came in at 500 barrels a day. It's my understanding, there's three more AFEs outstanding in the process of drilling the disposal well to be able to handle the water. So I think you'll see that area build out, but we were very happy to see those initial results up in that area. So now we feel good -- we feel good across the acreage and feel like it's all very promising.

John, I might add, this is Kelly, that you've got in excess of 150 wells to 200 wells have been drilled in that immediate area, not counting the 100 plus wells that we have.So I'd say from a proof of concept standpoint 200 to 300 wells, is a pretty good sampling.And that's not including the Mexico of course, there's a lot of work that needs to be done out there. It's still a lot of virgin territory, but there's a lot of good indications and early indications of noticable success.

Okay, great. I appreciate that. And maybe just following up asking the question a different way of the 363 potential locations you've identified, how many of those would you consider more derisked or maybe classify as high quality relative to the legacy assets that you have? Thanks.

Danny, Hollie?

Yes, the one thing they do have, they've been -- they've done a very good job of developing the property and to maximize reserves and to maximize their value by spacing the wells out, of that PDP or excuse me, the one P values that you see. I mean they have over 60 proven undeveloped locations, which that's a tremendous number, but considering how long they've been added. Beyond that the probables and possibles, we feel very strongly about, those are just one step out away from those existing wellbores. So there is a large number of these 363 potential wells that are -- what we consider to be high quality one well step out, two wells step out. It's all -- it looks good, I mean, obviously there are some areas that haven't had a lot of data yet, but the number of proven locations is strong.

And additionally, as you know obviously in that 363 locations, it contemplates going up in density in areas that already have been improved and have wonderful production profiles. So that also derisks some of those potential locations.

Our next question is from Joel Musante from Alliance Global Partners. Please go ahead.

Hi guys, congratulations on the acquisition. Most of my questions have been answered, but I did want to ask you about your current reserves got a little gassier and I was just wondering where was that from the San Andres or was that from the Delaware assets? And then just how should we think about the mix going forward given you probably have a two-rig program. So I guess I'll just leave it at there.

Yes, and Joel so one, we had a couple of drivers on that gas issue, one of them obviously is the Brushy Canyon. It is a little gassier area over there where we'd probably say, well, let's just take for example, the well, the Hugin, I mean even though it's our best oil well over there now, if you're looking at 300-plus in oil and almost 1 million, a day that's a valid one-third, two-third mix on the oil gas ratio. So that's a little gassier where over on the San Andres we're looking at 95% oil. So as we develop out the Brushy obviously, that'll add that, but I think with two rigs running over in the San Andres, it will mitigate that as getting too much gassier. The other thing that kind of drove the gas issue a little bit was when we built out our, we spend a lot of time and money last year building out a gas system to finally be able to sell our gas in the San Andres, a lot of that had been flared or vented for a period of time and we were finally able to start monetizing that, and I think that's a little bit of what drove that, but I think the big driver is probably the Brushy, but it's, I think with two rigs running in the San Andres it'll hold that gas ratio down.

Okay. And so, and where do you stand on the new assets in the Wishbone area? Do you have gas infrastructure there, what's the current mix of products?

Yes. As far as the mix goes they have about if you count in oil and liquids they are about and obviously Hollie can help me with this, it's probably in the mid '90s.

Yes.

As far as liquids and oil combined, oil is about 80% and the remainder of that would be liquids associated with it. They have just gotten the system put in, they have worked out a deal with a company called Santa Fe to build out the gas system as they are a midstream company and they finished their plant at the end of last year and they are now in the process of bringing that online and obviously there's a few bugs here and there, when, anything new you bring online, but we still feel like, and they do separate that and sell those separately. They actually control their liquids and sell those and market those themselves and in the gas they sell too separately. So they actually track those two things separate, but they do have a system built out. A part of the agreement with Santa Fe is that they build a pipeline to every battery, and so that's going to be a cost savings that they're not going to have to deal with as far as the cost that we had to go through. We didn't have that luxury down in our area. The gas purchaser in that area was going to do zero infrastructure work. So it was really on us to get that done. So with their deal with Santa Fe, they actually got a pretty robust system put in place and continuing to develop it out.

Our next question is from David Beard from Coker Palmer. Please go ahead.

Hey, good morning everybody. Just two quick questions. When you look at the -- let's say you exit this year, two rigs. What do you think your 4Q '19 to 4Q '20 production growth rate would look like?

Danny, you want to take a jump on that, of course, I know David knows we don't give formal guidance but let's maybe give some ideas.

No, I think Kelly's rendition to that and I think to give us a little chance to get our arms wrapped around this, but I think it's quite possible, we'll see that 20% to 40% range. I think that's very achievable. We will hopefully be able to narrow that down for everybody as we move through the year.

That's helpful. Just trying to get a sense of what the sort of internal growth rate is sort of with the status quo two rigs exiting the year and then maybe just back to following up on the inventory locations on the Wishbone acquisition, could you give us a sense maybe of how many of those 363 locations are in New Mexico?

Very few, there is probably in the neighborhood of in the range of 40 to 50 allocations in New Mexico in total.

I appreciate that -- Yes. I appreciate it. Thanks for all the color you guys and congratulations on the acquisition.

Thanks, David.

Our next question is from Ron Mills from Johnson & Johnson Rice [ph]. Please go ahead.

Good morning, guys. A couple of really just follow ups. I think you mentioned in your prepared remarks that the rocks are pretty similar, in this acreage versus your legacy acreage to the Southeast when we look at this acreage geologically, how similar is it? Do you think there'll be are there changes in the qualities that will require changes in the way you've been drilling and completing wells? Or is this really just almost a carbon copy of what you have down to the Southeast?

I hesitate to call it a carbon copy. It is a carbonate reservoir, it has a lot of thickness and so it's a little bit different from our current reservoir in that there are kind of multiple benches that are on lapping features that have developed through geologic time. So fundamentally, the rock matrix is the same, but the reservoir qualities are, there is some differences, and we're really excited to see what we can learn from it.

And to add on to what would Hollie said, you know, we do see a thicker oil column up in the Northwest Shelf up in the acquisition area and that gives us again the opportunity to potentially maybe to -- you know, you hear people talk about line reg kind of development out there, where you're slightly offsetting other wells going one a little shallower, one a little deeper. That's an opportunity that we see moving forward, again some of the other operators in the area are experimenting with that, we're very interested in how that goes. So in that area -- and in our particular area right now, we don't have that, really have that opportunity. I think we have a very good, we have just -- there's a little bit difference in the rock properties, one as the -- I'd like to point out about there is they don't make as much water as we do, which is very nice, it cuts down on lifting costs and disposal costs. So if they're just, they are the same, but they're different. And I think when you look at them on an economic standpoint, they are very similar, but they do have slightly different production characteristics.

Okay, great. And just to clarify, and I may have missed it earlier on, when you talked about ability to grow at 20%, are you talking about on a pro forma basis and is that '19 versus '18 or is that '20 versus '19, I'm trying to, I had the question and then your answer to David's prior question, I'm just a little bit more confused, when you talked about at two rigs 20% growth number, what asset basis and what timeframe are you talking about?

Ron, that's a good question and an opportunity to add some clarification to that. This is Tim. Welcome to the call by the way, Ron. Nice to have you on it. I, let's just be clear that when we talked about 20% annualized growth, we were talking about our legacy assets one rig and we pretty much took that position at year-end, as we were dropping from the two rig cadence that we had to the one rig, as we are going to start the New Year. So 20% and we really chose and we've continued to talk to analysts and others about the fact that it's really difficult for a company with our production profile to just go quarter-over-quarter and be right on line. So we feel very comfortable that the one rig on the legacy assets would have yielded right at 20% plus or minus annualized growth, from '18 through '19, now that we incorporate the Wishbone assets, we're going to bring that rig in or bring the rig in for their assets about mid-year or late or the first half of this year, we think that it's, that it's likely, that we'll add somewhere another 10% plus or minus growth to that, so 30% plus or minus, we think is pretty comfortable with the year and a half, or excuse me, with basically the first half of the year remaining with the one rig and then the second half of the year bringing in the second rig.

Okay, great, thank you very much and congratulations on this transaction.

Thanks Ron.

Our next question is from Richard Tullis from Capital One Securities. Please go ahead.

Hey, thanks, good morning everyone. Quick question for Kelly or Danny, you talked a little bit about possibly adding a third rig in 2020, where, what acreage would you likely add that third rig?

That's a great question. We, when we think of adding a third rig, Richard, you know, it could be even at the end of this year, could be at the first part of 2020, or the mid part of 2020 and it's going to be largely on seeing what we develop up on not all of these assets, but the assets that we have down in Andrews and Gaines County. So I mean we've got sort of a multitude of things we could do, we can even add a third rig out in the Brushy, with the stuff that's happening to us right now, we're really excited about it, because we have four areas that we have a lot of things happening and they are all good things. We're getting that kind of results and gains that we were hoping for. This acquisition is obviously very accretive to us, it's got the great kind of area that we'd like to drill in, we've got some legacy stuff, the acquisition that we just made in December is a great acquisition for us, adding another 50, 60 locations there, all super core locations and then things out in Brushy are happening wonderfully. So I mean I can't pin that down right now just because we know all of those are opportunities that are all happening at the same time, but they are good opportunities.

Thank you, Kelly. Just last question, sorry if this has been discussed already. What are the current AFE cost for the wells on the Wishbone acreage and what is the associated average lateral?

Yes, now they've been for the most part, they've been doing one mile laterals. They have done some mile and a half. As far as the associate, there's a slight difference in the way they look at things and the way we do, but overall, the drilling costs are going to be extremely comparable, the completion costs are comparable. And I'd only say that, in case you looked at their sales package. You'll notice that they show an AFE of about, between $2.5 million and $2.6 million per well and we're looking at 2 to 2.3, and that was associated infrastructure costs that go with that. So the difference there is that we don't buy our sub pumps and they do. And so they own those pumps and we ran ours and that's where the difference in those costs come in and -- it's a toss up, as to which way is the better way to do it, but that's the difference in those cost,But when you look at the actual drilling and completion costs, they are almost identical.

Thank you. This concludes the question-and-answer session. I'd like to turn the floor back to management for any closing comments.

Okay, well listen, thank you everyone. We know that this is something that people have been anticipating. And I think hopefully it answers a lot of questions at all levels. And I hope that -- I hope the enthusiasm that management has is contagious, and that you feel the same and will continue to be supportive. Follow-up questions, always feel free to reach out to Bill Parsons, Investor Relations. And once again, thank you and all have a good day.

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