Ring Energy Inc (REI) 2018 Q4 法說會逐字稿

Greetings, and welcome to the Ring Energy 2018 Fourth Quarter and 12 month financial and operating highlights Conference Call. (Operator Instructions)

As a reminder, this conference is being recorded. I'll now just 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 to -- and all listeners to our fourth quarter and 12 month 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 12 months ended 12/31/18. At the conclusion of our fourth quarter and 12 month '18 overview, we will discuss the acquisition announced yesterday, of the assets the company acquired from Wishbone Energy and their immediate impact for 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 from last year. 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 completed explanation, I would refer you to our released issued Tuesday, February 26, 2019. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com.

Although, it does not affect to the BOE value as 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 1.

Of the 3 months ended December 31, 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 31, 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 in 2017.

For the 3-month period of 2018, the net loss includes a pretax realized loss on hedges of $4.6 million, a pretax unrealized gain on hedges -- unrealized 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.

The 3-month period of 2017, net loss included a pretax 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 pretax realized loss on hedges of $4.6 million, a pretax 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 of 2017, net income included a pretax 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 3 months ended December 31, 2019, 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 31, 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 was $53.78, an increase of 16% from the 2017 price.

Production cost per BOE for the 3 months ended December 31, 2018 increased to $13.76 as compared to $12.17 in 2017.

For the year ended December 31, 2018, production cost 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 revenue 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 3 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 (sic) [2018], the rate increased from $14.60 per BOE to $17.75 per BOE.

Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts.

As to total, the 3 months 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 or G&A increased $486,000 for the 3 months ended December 31, 2018, and $2.4 million for the year ended December 31, 2018 as compared to the same period in 2017.

On a per BOE basis, this equates to a reduction from $6.51 in 2017 to $5.77 in 2018 for the 3-month period, and from $7.31 from 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 3- and 9-month and 12-month period are primarily a result of increased production volumes.

On a diluted basis, the loss per shares for the 3 months ended December 31, 2018 was $0.11 as reported.

Excluding the $6.4 million pretax, unrealized gain on hedges, the $14.2 million ceiling test write-down and a $780,000 noncash 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 pretax unrealized loss on hedges and the additional tax provision of $7 million and a $922,000 noncash charge for share-based compensation.

For the year ended December 31, 2018, net income per share was $0.15 as reported. Excluding these $4 million pretax unrealized gain on hedges, the $14.2 million ceiling test write-down and a $3.9 million noncash 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 pretax unrealized loss on hedges, the additional tax provision of $7 million and a $3.7 million noncash 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 have cash on hand of $3.4 million.

For the 3 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 wouldn't mind, Kelly, just review the fourth quarter 12 months operations for us please.

Thank you, Tim, and thank you, everyone, for joining the call today. So in the 3 months ended December 31, 2018, company drilled 12 new horizontal wells. Company drilled 8 San Andres wells on the Central Basin Platform asset. We had one San Andres well on our North Gaines property and 3 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 -- 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, about 103 BOE per 1,000-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 1,000-foot. So for the 12 months ended December 31, company drilled 57 new horizontal wells, 49 San Andres wells on a CBP asset, 3 horizontal San Andres wells and one horizontal test well in the North Gaines property. We had 4 horizontal Brushy Canyon wells on our Delaware Basin property. And for the 12 months ended December 31, we filed IPs on 57 new horizontal wells and the average on the 57 wells was 432 BOE per day and again, were all 103 BOE per 1,000-foot.

In the North Gaines area, in the fourth quarter of 2018, we drilled one new horizontal well on that property. It was the Ellen B. Peters #3H. That's a first horizontal well the company has used, what we call that, plug-and-perf completion method versus the sliding sleeve. We've talked about this in the past, which 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 ore cut in the gains that we were experiences further south of about 30% to 40% of oil versus water.

The water production on this well is 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 of their preparation of an ongoing drilling development program going in 2019.

Moving on to the Delaware Basin asset. We have -- we've got 3 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 Southwestern area of the property. Two of the new wells were drilled in the Northeast. I'm going to elaborate on that here in a moment.

As many of you might remember, we drilled and completed that first Brushy Canyon well, which again is the Phoenix #1H last May. That well was drilled very high on the structure and IP 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 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 advantage there by moving down dip and getting a little 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 it about 290 oil and about 500,000 cubic feet of gas a day. Now we've had some days off, just to tell you that the oil production has been as much in a 24-hour period as double that, in the 500-plus maybe even 600 at times. We've had gas also as much as 700,000, 800,000 maybe even 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 pumping that well maybe a couple weeks ago. So it's still in the testing period, and we're just getting it kicked off.

We since offset the Hugin well with a 2H well, I guess it is, I may not have my number on it exactly right, but that well is -- we just put the pump in it I think in the last week. So we expect 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 what the 1H was doing. So just not to get you confused, we've got 2 Phoenix wells, we now have 2 Hugin wells and 1 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 installed. 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%.

Net production of 600,000 BOEs for the third quarter of 2018 and that's an increase to fourth quarter over the third quarter about 4%. In December 28 (sic) [2018], average net production including flared gas was approximately 7,099 BOEs as compared to net production of 5,352 BOEs for December 2017 and that's about 32.5% increase in net daily production of 7,294 in September 2018, another 2.6% decrease. So for the 12 months ended December 31, 2018, net production including flared gas was 2,262,800 BOE per day -- I'm sorry, BOEs total as compared to 1.402 million BOEs for the 12 months ended December 31, 2017 that's 1-4-0-2, 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 our operations. Danny?

Sure. Thank you, Kelly. Before we go into what we're currently doing at this time, I wanted to address a few issues that we've had some questions about, one of those being the difference between sales as we reported for the quarter versus production. It's approximately a 30,000 BOE difference in that.

That amount -- as about 17,000 BOE of that was associated with the flared gas. And the reason we report that, obviously as production is -- it's going to show up on the -- it shows up on the state report. 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 line fill, as we build out our oil system, and our oil gathering system. Obviously, you have to fill up the tanks, and you have 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 build that we had there at the end of the year. Did not mean that we weren't able to move the oil, it's just that 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 as everybody knows, over the years -- this last year, we've seen differentials to WTI, WTS up to $16 per barrel. And that's before we add on the transportation cost, which was very -- even though process were climbing, our net -- the net prosper barrel was not necessarily climbing due to differentials. That -- I'm very happy to report it as of -- to 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 a -- 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 usually a sour heavier crude. And also with the sanctions on Venezuela, which has shut down a lot of that incoming high -- excuse me, very low gravity, high-sulfur content oil, which has actually made our sour barrels very attractive right now as refineries need to dilute down some of the very sweet crude that they get from the Midland and Delaware Basins. So we're very excited about that looking forward. I looked down the strip moving forward for the year.

The worst price I saw was about $1.83 differential and that was in the September-August range. So -- and I think those will straighten out as we move through the year. As far as current operations, we have one rig we're drilling right now. We announced earlier, or the end of the last year early this year, that we would be going to a 1-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 2 rigs running in December. We laid those 2 rigs down middle of the month as we kind of reached our budget year, went ahead and laid those down, and we picked 1 rig back up on January 1 and that rig drilled 4 disposal wells, 3 in the Delaware Basin. Due to -- And those were drilled due to expiring permit that we did not think we were going 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 in our -- 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 in -- on January 1, started drilling the San Andres horizontal wells. And we've, so far, to date, we've drilled 3. 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 our the -- from 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 -- particularly on the Hugin #1H. Kelly mentioned that, it's been doing very well. And it is. We've had some days on average just a little over 300 barrels a day, but we've had some days in the 500 and 600, 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 rate. Some of it has to do laying the rigs down. When we laid the rigs down, we -- I think we completed one or 2 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 to 60 to 90 days to actually start cutting oil. So all those kind of together cause 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 completions start 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 made it public is the -- because of the acquisition. And as you can appreciate this acquisition changes everything. So 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 recent activity last year but add anything more to that, you'd like to David on that same level.

All right. Thank you very much, Tim. We ended Q4 on a high note with an acquisition from Tessara energy, it was a Carlyle funded company that consisted of about 4,800 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 add as it's contiguous to our current leasehold, and it offset 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 the water disposal infrastructure that readily plugged in to Ring's existing disposal systems as well as oil and gas pipeline

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chances are take away capacity. And 2 other separate bolt-on transactions. We picked up an additional 550 net acres of leasehold that added 9 high-quality locations, again, in one of our newer core areas. Both of these transactions were added for less than $1,000 an acre and are significantly accretive on improved PV-10 basis.

In our Northern Gaines area, and this was just recently, we closed on an additional 5,000 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 drilled our best wells in that area.

All of these transactions were greatly impactful through their approximately 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'll 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 month financials operational overview. 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 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 release and/or if you haven't been able to go on the website, I would suggest you 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 investor's tab and that'll allow you to follow along with some of the slides that we're going to focus on.

So with that, I'm going to start off by turning this over to Kelly, and you can get us kicked off this, Kel.

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 the last year, probably around August, July time, right, when we become 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 be final bidder group in January. So we had all 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 #3 or Slide #3 is the one I'm referencing, in particular right now. And so I'll just give you the summary highlights here. So it's immediately accretive acquisition to us, the $300 million purchase price, which is $270 million cash and $30 million common stock. Currently, our NAV per share is estimated about $7.46, and it 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 sort of the key point associated with our production reserves and EBITDA, it doubles our production, essentially doubles our crude reserves, it doubles our future EBITDA. That's why we're saying, it's immediately accretive or very accretive as time goes on. So increases our prospective horizontals, San Andres locations by 363. Our credit facility, we increased it from $500 million to $1 billion in the facility. Following 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, there's no capital markets required to fund the acquisition. We have a low projected leverage of -- at that point in time, half the acquisition of 2.2x by year-end 2019 and estimated about 1.5x 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. That's a great overview. Yes, Danny and Hollie, you mind 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 very we're happy about in this and you can reference Page 4 or 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 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 are 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 to be able to lower that G&A.

Moving on to Page 5, we can talk about -- some of these points were covered by Kelly but as far as the transaction overview. Obviously, we do have the $300 million price, the $270 million of it 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 -- we'll be picking up just a little under 50,000 gross acres and a little over 37,000 net.

Mostly contiguous. That's another thing we're very happy with, that the properties are very compact and very contiguous, and so it makes it very easy to operate. 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 to develop this play. We've been watching this play developed since 2013, 2014 time frame when it really got kicked off by Manzano and then Walsh, were the 2 main players they kicked that off. Manzano's the one that really proved that she could step out away from these existing fields up in this area and get good economic production. Those properties have since, obviously, been acquired by Steward, who has done an extremely good job of developing those properties. They identified some issues and 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. The other operator in the area who's also really helped prove this acreage up is Riley, Riley Permian. They've done a fantastic job also of coming in and developing the property. What we really like about this property and what we find very attractive is, we are sandwiched between those 2 players.

So you have excellent properties up from Steward, you have excellent properties from Riley and this

property just fits right in there between them.

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'll be obtaining and then obviously we are in quite a few of their wells. So there's 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 7 or 8 wells per section. We have a study done by Von Gonten, out of -- a very well known reservoir engineering firm out of Houston, which indicates a potential for 8 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. That -- anyway, that's exciting, and our well count is strictly based on 6 wells per section. So there is potential down the road for additional stats in there.

Another thing that made it very attractive to us was their infrastructure, which they've kind of followed a 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 fee. They have several very large blocks of acreage. They've drilled their own disposal wells. They've drilled their own water supply wells for 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 will 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, it doesn't mean the 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 rock is a little bit different, which gives us a little different production profile. And so -- but they'll 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 5 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 a -- 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 2-rig program. One of the things that I've mentioned, and Hollie, again, will go into this is that it does help us to have a more consistent production ramp, more predictable. We have a high variability rate, obviously, as you are 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're still about the same, but there is 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 what we're talking about. You can look across that acreage area. 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 still very, very attractive rates. Like I said, they are right up on par with what we already have.

Page 8. A little bit more on the infrastructure. As I mentioned, they do have their own surface. They own approximately 1,385 acres of surface, mostly in 3 tracts spread across the acreage. They have 21 saltwater disposal wells. They have capacity of 178,000 barrels a day. Their water cost for disposal is $0.04 per barrel, which is extremely attractive. They drill 4 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 -- we can fill a frac pond up probably in about a couple of days with that. So it gives us a nice capacity build 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 5 frac ponds that they've scattered around the acreage. It gives them good access to frac ponds. They have their own complete caliche pits, and people wonder why that's important. It's 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 sits. 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 reserves.

Thank you, Danny. So as Danny had mentioned, this is equally as good reservoir as what we're seeing in our 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, so we're not seeing the huge variability that we do see in Andrews.

Overall, as Kelly mentioned, the purchase price is $300 million, with a proved 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 daily 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 are 66 horizontal PUDs that are bookable at SEC standards, which gives us a lot of room for growth and that is at the downspace [pit] 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 8 wells. So there's 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 it's 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 increase 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 107%. We double our current production, and we're seeing a 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 metrics per share.

All right, Hollie. Thank you. If everyone -- and again, if you're able to view this or you have it in front of you, if you can 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 per -- 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 as you drop down and you can see in the 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 76,000-and-change to the 37,000-and-change that we acquire for a total of 113,000 plus. If you're looking that on a per-share basis, we go from 1,202 to now 1,660. That's a 38% increase.

As you look at the prospective locations that Hollie pointed out, I might add -- and I think Hollie and Danny and everybody will agree with this is that this isn't goat pasture out there. This is a quality area, and although they don't fall in the categories of total proved or probables or possibles, they are really really high-level opportunities for prospective locations. We go from 882 to 1,245. That's 14 per -- 14 locations per share stand-alone. When you add the acquisition, it jumps to 18, 31% increase. And lastly, on the proved -- on a proved basis, on a PV-10 basis, we go from $542 [million], we add the $582, we've got a $1.123 billion 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 a pro forma combined $1.123 billion. 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 If you -- I guess, bottom line is if you liked us today, I think you pretty have to love us today.

So with that, I'm going to turn this back to Danny for any closing thoughts that he may have as it relates to operations, and then you can give it back to me, Danny.

You bet, Tim. This does -- this acquisition does a tremendous amount of things for us, especially from a predictability standpoint. And this is one thing I've shared with Tim and Kelly and the board as we've moved through this process is, what it really does is it allows us to get control of our completion rate and the drilling rate. Dropping to 1 rig, obviously, presents some issues as we've mentioned before. We're -- our frac crew actually spends more time away from us 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 that frac crew back. We can start doing multiple completions at a time instead of just doing one offs as we move through with 1 rig. And so it really brings us some tremendous opportunities to level things out. We don't have to add a lot of staff, which, I think, is going to be very good for us. And I 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, 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. We -- ultimate value that company could have grown. And all those deals were very effective, but I can tell you and I can say 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 to 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 on 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.

I wanted to ask -- as you look at -- I think you talked just now about the completion crew, but also kind of how you think about -- how you'll attack this when they're together. I assume you run 2 rigs. Will it 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, do 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 running on the existing properties, drilling our core area. And then we'll have the second rig up there, working with -- on the new Wishbone acreage. And as I've mentioned, now the -- it really takes about 3 rigs to keep that frac crew busy. So we're moving towards that. There -- I guess, at some point, there will be a possibility that we'll 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 yes, we're looking forward to that.

Sure. I appreciate that. And then maybe just on the financial side of it, obviously, you moved the credit facility higher. Tim, you guys have always been pretty debt averse and adapted to pick 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 strategy going forward with the added leverage?

Yes, you bet, Jason. Two good points. Let me just, before I address those, if I may, go back to the conversation you were having that Danny was responding to. One thing that -- again, I know we've 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 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 the rig 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 what -- 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 and managing our balance sheet by going to the 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 the first year, year '19, we kind of look at somewhere about 2x the EBITDA ratio, and I think we see that manage down to about 1.5x or 1.5x for 2020. I will add to that, Jason, that if capital markets improve or when they improve, not if, I say, probably not very optimistic on that, but when they do improve, we'll consider that. We'll look how things are going. As Danny mentioned, I think that there isn't any question that we're going to feel very comfortable about reaching our cash flow neutral, cash flow positive as we go into the second half of this year. Strictly, as we start adding surplus to that capital, we start looking at year-end and rolling into '20, is the possibility of adding another rig, a possibility of maybe even further consolidation. There's no question 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 had some mild criticism. But I just want to show as an example, last year, about a year ago right now, we raised equity. We've raised capital somewhere in $80 million range. If we had not done that and we would have started using and borrowing and 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 and 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 buyers. There were multiple ideas coming to the table on the Wishbone assets. And I believe as certainly as we are 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.

Our next question is from Neal Dingmann from SunTrust Robinson Humphrey.

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 that the rig doesn't come out until May. Is that still the case whether you run 1 rig, 2 rigs? Maybe you could just talk about in broad terms how you think about the guidance there, Kelly, for you or Tim.

Sure. Absolutely. That growth rate that we were giving guidance on, the 20% was related to 1 rig, and 1 rig will do that. So we're very comfortable with that. Obviously, if we have the second rig on, depending on how the wells come on, it could be as much as double, 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 towards the growth percentage. So I think it is very likely 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 long ways to ensure that. And so I think that kind of -- I think the 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 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 and second around the free cash flow. The thought about -- Danny made the comment about you can keep -- better keep a full-time frac spread if you had a third seems to me that would even add to more capital efficiencies. So I guess, just for any (inaudible) that 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 the accretion 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 was November 1, but from an operational standpoint, 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 site. 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've 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 it going to make sense for us, once we see we cross that threshold from cash flow neutral to positive, how soon we bring in that third rig and how critical that would be? And I don't think there's any question. We've got some learning -- we've got some feel our way a little bit here, but that's what we're all thinking as well.

Okay. And then if I can just sneak one more in. Does this change -- I guess, maybe question for Danny. You definitely were having success in the Brushy, some of those areas about what you may or may not do there by having this acquisition. Or really, does it change anything in that regards?

No, it doesn't, Neal. We really like the Brushy. We think the returns over there are 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. Obviously, the stuff in the San Andreas 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 -- we 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 ad hoc a rig every once a while and go drill one, pick a third rig up for a well and drill 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.

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 in that close, maybe, it's -- something less than 6? Or is 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's running 2 rigs? Just wanted to make sure is all that kind of accurate?

Yes, I'm going to take the first half of that, and 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, they, Wishbone, stopped drilling in the third quarter, as they were putting this well up for -- this package up for bid. They did drill at a pretty rapid rate up till the third quarter. From there on, they were concentrating on getting the wells they had drilled completed. And so they really -- there hasn't been any new wells adds for that property since probably late November. So December, January are just kind of on cruise control. There is not a rig running out there at this time. It's possible to 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 it'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'll 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 the new Ring Energy, maybe for Kelly or Tim, what do you think the 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's a return of capital to shareholders? Or is this kind of a growth within free cash flow? Or just, generically, how you view since you're double on your production base and getting some more inventory? What -- how should investors think about the new Ring Energy?

Yes. You know, Jeff, I think that -- this is Tim, I think there's 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 put them back to the ground as it relates to value return and, ultimately, 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 keep our eyes forward, keep drilling. And not to say that there's not other opportunities on the acquisition side. I do believe and, as I mentioned earlier, we've become the consolidator. And I think there will be other assets that we'll see along the way or opportunities or ideas that we'll 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.

Your next question is from John Aschenbeck from Seaport Global.

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? Because just looking at the merits of the acquisition, I -- due to an implied valuation on a dollar per acre basis or dollar per location basis, that isn't too dissimilar to the valuation implied 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 real value proposition of this acquisition as opposed to buying your own shares, is it simply an increased scale? Or are there, perhaps, some other ways to unlock value with this deal that maybe aren't yet reflected in your estimates?

Yes, I think it's a 2-part answer as well, John, and thank you for that question. This is Tim. I don't think there's any question that as time goes on, the unlocked value, and I think Hollie touched on it earlier with the remaining locations that are prospective 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, yes, we would have -- we considered, and there were some people that had 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've been locked out of this deal. There isn't any question about that. And 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've 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 if the company is seeing or realizing the value on top of that PDP is going to be much, much bigger and better for the shareholder as compared to the possibility of going back and purchasing those shares out of the market and using the gun -- the dry powder for that. So I hope that answers your question, but that's the way I look at it. And Kelly has a comment on that. Go ahead, Kelly?

No, I'm good, Tim. It's well said. That's exactly the case.

Okay, great. Yes, 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 service 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 unutilized 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?

John, that is really an excellent point. In fact, you can even broaden that question by saying, okay, the unlocked value, is that something that we consider doing at some point in time that would allow us to raise capital rather than borrowing or even going to the capital markets. Not only think about that, but think about Delaware, think about lower -- rather south at the platform. We have now 3 systems, SWD systems, and everybody on this call pretty much is familiar with how those kinds of assets have been trading lately and the demand for them. 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 and make sure that we adequately have room and space to take care of our own. Beyond that, there's certainly the opportunity to add up an income stream line on it. No doubt about that. And then there's lastly the possibility of monetizing, as you say. Once these reach capacity or close to it, that can make some real sense. But we'll just wait and see, but believe me, we've looked at that very closely, John.

Great, Tim. I appreciate it. And one more, if I can 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 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 Lee County. So I would just love to get a feel for your overall confidence in 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 a supporting detail or data points that you have internally that gives you that confidence.

Yes, good question. Danny, Hollie, could you guys take that, please?

Yes. No, John, we've looked at this from a geological standpoint, 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 the play in Walsh. So obviously, that's 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're 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 -- 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 3 more AFEs outstanding, and they're 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 no, 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 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 New Mexico, of course. There's a lot of work that needs to be done out there. There's still a lot of virgin territory, but there's a lot of good indications and early indications of noticeable success.

Okay, great. Appreciate that. And maybe just following up asking the question a different way. Of the 363 potential locations that 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?

Danny? Hollie?

Yes. No, 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 1 P value that you see, I mean, they have over 60 proven undeveloped locations, which -- that's a tremendous number of PUDs considering how long they've been at it. Beyond that, the probables and possibles, we feel very strongly that those are just one step out of way from those existing wellbores. So there's a large number of these 363 potential wells that are what we consider to be high-quality 1-well step-outs, 2-well step-outs. It's all -- it looks good. I mean, obviously, there's some areas that haven't had a lot of data yet, but the number of proven locations is strong.

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

Our next question is from Joel Musante from Alliance Global Partners.

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 asset? And then just how should we think about the mix going forward, given you probably have a 2-rig program? So I guess, I'll just leave it there.

Yes. Joel, yes -- so -- 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 probably say, well, let's just take for example the well, the Hugin, I mean, even it -- 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 -- that is 1/3, 2/3 mix on the oil-gas ratio. So it'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 will add that. But I think with 2 rigs running over in the San Andres, it'll 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 spent 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 2 rigs running in the San Andres, it'll hold that gas ratio down.

Okay. 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 production?

Yes. As far as the mix goes, they have about -- if you're counting oil and liquids, they're about -- Hollie can help me with this, probably in the mid-90s as far as liquids and oil combined, oils about 80% and the remainder of that would be liquids associated with it. They have just gotten a system put in. They had worked out a deal with a company called Santa Fe to build out the gas system as their 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 and sell those separately. They actually control their liquids and sell those and market those themselves. And then the gas, they sell too separately. So they actually track those 2 things separate, but they do have a system built out. Part of the agreement with Santa Fe is that they build 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 costs 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 0 infrastructure work. So it was really on us to get that done. So -- but with their deal with Santa Fe, they've actually got a pretty robust system put in place and continuing to develop it out.

Your next question is from David Beard from Coker & Palmer.

Just 2 quick questions. When you look at, 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, do you want to take a shot 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 of 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'll, hopefully, be able to narrow that down for everybody as we move through the year.

No, no, that's helpful. Just trying to get a sense of what the sort of internal growth rate is sort of with the status quo 2 rigs exiting the year. And then maybe just back to following up on the inventory locations. On the Wishbone acquisition, can 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 locations in New Mexico total. (inaudible)

Our next question is from Ron Mills from Johnson Rice.

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 you look at this acreage geologically, how similar is it do you think there will 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 carbonated 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.

Yes. And to add on to what Hollie said, we did 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 do -- you hear people talk about [line rack] kind of development out there where you're slightly offsetting other wells, one little shallower, one little deeper. That's an opportunity we see moving forward. Again, some of the other operators in the area are experimenting with that. We're very interested to see how that goes. So in that - our particular area right now, we don't have that -- really have that opportunity. I think we have very good -- we have just -- there's a little bit difference in the rock properties. One other thing I'd like to point out about theirs is that they don't make as much water as we do, which is very nice. It cuts down on lifting costs and disposal costs. So they're just -- they're the same, but they're different. And I think when you look at them on an economic standpoint, they're 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 talk 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 that 2 rigs, 20% growth number. What asset basis and what time frame 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, 1 rig, and we pretty much took that position at your end as we were dropping from the 2-rig cadence that we had to do 1 rig as we were going to start the new year. So 20%, and we really chose and we continue 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 online. So we feel very comfortable that the 1 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 another rig in or bring the rig in for their assets about mid-year or late -- first half of this year. We think 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 1.5 years -- or, excuse me, with basically the first half of the year remaining with the 1 rig and then the second half of the year bringing in the second rig.

Our next question is from Richard Tullis from Capital One Securities.

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, it could be even at the end of this year or could be in 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 only 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 4 areas that we have a lot of things happening, and they're all good things. We're getting that kind of results and gains that we're hoping for. This acquisition is, obviously, very accretive to us. It's got the great kind of area that we like to drill in. We've got some legacy stuff. The acquisition that we just made in December is a great acquisition for us, add another 50, 60 locations there, all Super Core locations. And then things out of 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're good opportunities.

And just last question, sorry, if this has been discussed already. What are the current AFE costs for the wells on the Wishbone acreage? And what is the associated average lateral?

Yes. No, they've been -- for the most part, they've been doing 1 mile laterals. They have done some 1.5 miles. 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 look 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 $2.2 million, $2.3 million and that's with associated infrastructure costs to go with that. So when -- the difference there is we don't buy our subpumps and they do. And so they own those pumps, and we rent 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 costs. But when you look at actual drilling and completion costs, they are almost identical.

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

Okay. 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 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.