Ring Energy, Inc. (REI) Q1 2019 Earnings Report, Transcript and Summary

Greetings, and welcome to the Ring Energy Inc. 2019 First Quarter Financial and Operating Results. 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. It is now my pleasure to introduce your host Tim Rochford, Chairman of the Board of Directors. Thank you, Mr. Rochford you may begin.

Thank you, Doug and welcome all listeners to our first quarter 2019 financial and operations conference call. Once again my name is Tim Rochford, Chairman of the Board. Joining me on the call today is our CEO, Kelly Hoffman; David Fowler, our President; Danny Wilson, Executive VP and in charge of Operations; Randy Broaddrick, our Chief Financial Officer; Hollie Lamb, Vice President of Engineering; and also joining us today is Bill Parsons, Head of Investor Relations. So today, we will cover the financials and operations for the first quarter ending March 31, 2019. We will review our results and provide some insight as it relates to the current progress thus far in – or excuse me, in the second quarter of 2019. At the conclusion of our presentation and the overview, we will open it back up to the operator and we look forward to any questions that you all may have. So with that said, I'm going to turn it over to Randy and ask Randy to review the financials. Randy?

Thank you, Tim. Before we begin, I would like to make reference that any forward-looking statements, which may be made during this call, are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our – release issued Wednesday May, 7 2019 – sorry, that's Tuesday. If you do not have a copy of the release one will be posted on the company website at www.ringenergy.com. On April 9, 2019 we closed on the acquisition of the Northwest Shelf asset from Wishbone. The effective date per the purchase document was November 1, 2018. However, the effective date for accounting purposes was February 1, 2019. The effective date for accounting purposes was determined based on when we had control of or decision-making ability over the assets. The activity from November 2018 through January 2019 was accounted for as a purchase price adjustment while the revenues and related expenses for the acquisition are included in our operations beginning February 1, 2019. For the three months ended March 31, 2019 the company had oil and gas revenues of $41.8 million, and net income of $11.1 million, as compared to revenues of $29.9 million and net income of $5.7 million in the first quarter of 2018. For the three month period of 2019 the net income includes a pre-tax unrealized loss on hedges of $341,000; acquisition-related costs of approximately $3.5 million; and a deferred tax benefit of $3.9 million. Without these items, net income would have been approximately $10.3 million. The three month period of 2018 net income includes a pre-tax unrealized loss on hedges of $791,000; a pre-tax realized loss on hedges of $1.5 million; and an additional tax provision of $1.2 million. Without these items net income would have been approximately $8.6 million. For the three months ended March 31, 2019 our oil price received was $50.31 per barrel, a decrease of 17% from 2018. Our gas price received was $2.18 per Mcf, a 39% decrease from 2018; and our natural gas liquids price was $21.41 per barrel. On a per BOE basis, the first quarter 2019 price received was $47.57, a decrease of 18% from the 2018 price. Production cost per BOE for the three months ended March 31, 2019 decreased to $10.71 as compared to $11.23 in 2018. We are still evaluating the ultimate impact the Wishbone acquisition we'll have on our ongoing production cost per BOE, but we expect it to be at or below our historical average. Most production costs are based on values of oil and gas sold so our production taxes expense is directly correlated to the commodity prices received. Our production taxes as a percentage of revenues remained relatively flat and should continue to be. Our total depreciation, depletion and amortization or DD&A including accretion of asset retirement obligations per BOE decreased for the three months ended March 31, 2019 to $14.96 per BOE, as compared to $16.82 per BOE for the same period in 2018. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts. As to total amounts the three-month period ended March 31, 2019 increased approximately 52% from the comparable period in 2018. This was based on increased sales volumes. Our overall general and administrative expense increased $3.8 million for the three months ended March 31, 2019 as compared to the same period in 2018. However, as referenced previously, we incurred approximately $3.5 million in acquisition-related costs. Without this, the increase from 2018 is approximately $340,000. Excluding the acquisition-related cost on a per BOE basis, this equates to a reduction from $5.99 in 2018 to $3.90 in 2019. On a diluted basis, the income per share for the three months ended March 31st, 2019 was $0.17 as reported. Excluding the $3.9 million deferred tax benefit, the pretax unrealized loss on hedges of $341,000, the $3.5 million acquisition-related cost included in G&A and the $834,000 non-cash charge for share-based compensation, the net income would have still been $0.17 as the pluses and minuses wash out. This is compared to income per share of $0.10 as reported or $0.16 per share excluding the $1.2 million additional deferred tax provision; a $791,000 unrealized loss on derivatives; the $1.5 million pretax realized loss on hedges; and the $1.1 million non-cash charge for share-based compensation in 2018. As of March 31st, 2019, we had $84.5 million drawn on our credit facility and had cash on hand of approximately $2.6 million. In conjunction with the acquisition, we increased our credit facility and borrowing base and extended the term for an additional five years. The borrowing base is now $425 million. For the three months ended March 31st, 2019, we had adjusted EBITDA of approximately $24.2 million or $0.38 per diluted share compared to approximately $19.2 million or $0.33 per diluted share for the same period in 2018. As supplemental information and for comparative purposes, after adjusting for the $3.9 million deferred tax benefit and backing up all of the acquisition-related items, the Ring only first quarter 2019 earnings would have been approximately $0.04 per share on revenues of approximately $26.7 million. Adjusted EBITDA would have been approximately $15.8 million or $0.25 per share. With that I will turn it back over to Tim.

All right, Randy. Thank you. I appreciate you doing that. I'd like to ask Kelly to give us a recap on the first quarter operations please.

Thank you, Tim and thank you everyone for joining us. In the three months ended March 31st, 2019 the company, using one drilling rig drilled seven new horizontal wells and four saltwater disposal wells. We also drilled six new horizontal San Andres wells on our Central Basin Platform asset and five wells which were one mile in length and one was 1.5 miles. In addition, the company drilled one new horizontal Brushy Canyon well on our Delaware Basin asset. And it was a one mile well as well. We also drilled seven wells, six of which -- of the seven -- I'm sorry completed seven wells. Six were drilled in the first quarter of 2019 one of which was drilled late in the fourth quarter of 2018. And of the seven wells, four were completed prior to the midway point and had a -- and those were the ones that had an impact -- significant impact on first quarter production. In the first quarter, we filed initial potentials on four of the seven completed wells. The average IP on the four wells was approximately 575 barrels of oil equivalent per day or 132 BOE per 1000-foot. Three of the four wells -- please take a note three of the four wells IP were on new leases -- the new leases that we acquired and announced in December along with the Carlyle acquisition. As a result, the net production in the first quarter 2019 is approximately 569,130 BOEs as compared to net production of 507 BOEs for the first quarter of 2018 and that's an approximate increase of 12.3%. Net production of 608 BOEs in the fourth quarter of 2018 an approximate 6.4% decrease. March 2019 average net production was approximately 6,381 BOEs as compared to net production of 6,005 for March of 2018 and that's an increase of 6.3%. And a net daily production of 6,908 in December 2018 and that's a 7.6% decrease. So in December, we announced -- December 26, 2018 announced that we'd closed the Carlyle asset in Andrews County. And along with additional -- and a handful of small leases that we added to that approximately 5,300 net acres and that added about 55 new gross horizontal locations. These are great locations. It's in the middle of the core. It's the best core some of the best stuff that we drilled in our legacy assets. On February 26, 2019, we announced we had entered into a definitive agreement with Wishbone Partners LLC to acquire their Northwest Shelf assets located primarily in Southwest Yokum County and part over in the -- a part was over in the Eastern portion of Lea County. And then on April 11, we announced we closed the acquisition. We estimated pro forma net production for the first quarter ended March 31st, 2019 that the company included the acquired Wishbone assets approximately 1,050,000 BOEs. There had been no active drilling or development on the Wishbone asset since October. In our opinion, this transaction is a real game changer. It immediately doubled our estimated production future EBITDA proved reserves in our PV-10. Our current combined net production is approximately 10,600-plus barrels a day and that's about where we expected it to be given as I mentioned there was no maintenance going on and there hadn't been any wells drilled since I think September or October last year. And as I said we did add a meaningful amount of additional acreage there to 38,000 net acres which makes Ring the largest horizontal San Andres Company on the Central Basin Platform and Northwest shelf. As we stated last December, we began the first quarter of 2019 and had some specific goals in mind and that was to maintain production growth and achieve cash flow neutrality as rapidly as possible. These two acquisitions alone ensure our ability to continue to post meaningful growth and not sacrifice our goal of becoming cash flow neutral as soon as possible. One other further reminder and that is that we will release as we have said a more complete budget here mid-year and as we get into the discussion today Danny and Hollie are going to give you a little more color on that. And with that, I'd like to turn it over to Danny and Hollie for some continued operational update.

All right. Thank you, Kelly. We appreciate that. From Kelly's recap of the Q1 operations, you can see that we had a reduced activity level during the quarter, especially compared to the activity levels we saw in 2018. As we reported at the end of 2018, we laid down both of our drilling rigs in mid-December and then resumed drilling in January with one rig drilling on the Central Basin Platform acreage and one rig drilling on our Delaware acreage. During the quarter, the CBP rig again drilled six horizontal San Andres wells and one saltwater disposal well. The Delaware rig drilled one horizontal Brushy Canyon well and three saltwater disposal wells and then was released. And the reason for drilling the saltwater disposal wells during that quarter was we had some permits expiring and rather than going back through the permitting process, we wanted to go ahead and get those taken care of. We continued operations with one rig until the closing of the Wishbone acquisition on April 11th. The following day, April 12th, we spudded our first well in the Northwest Shelf. As noted in the Q1 operations report, we did have a decline in production during the quarter as compared to Q4, but this was as a result of shutting the rigs during December and then effectively restarting with just one rig in January. It took us a little time to ramp the activity level back up but we are now running both the rigs at full capacity. As a point of clarification, we resumed drilling with just one rig as part of our goal in our plan to reach cash flow neutrality by the end of 2019. Obviously, the closing of the Wishbone acquisition gave us the ability to restart the second rig and still reach that goal. To update everyone on the status of a couple of our projects that we have going on. In the North Gaines area, we still have two wells actively producing the Ellen B. Peters 3H and 4H. We reported in our operations reported at the end of that -- last quarter that we were making 200 barrels of oil per day and we're still flat at 200 barrels of oil per day. The wells are holding up very nicely. Again those have a particularly good oil to water cut. We make about 25% oil and about 75% water which is significantly better than we see in other areas that we operate. During Q1, we acquired a saltwater disposal well a few miles away from our producers, which will allow us to stop hauling water and this will result in significant cost savings moving forward that when we were hauling water we were paying about $1.50 per barrel to haul that away. After buying the disposal well and we've already laid a line to it and are using it currently our costs are going to drop below $0.20 per barrel. So, it'll be a significant cost savings moving forward. And it also gives us the ability to be more active in that area and have much more favorable economics once we start developing that. In the Delaware, our Brushy Canyon wells continue to exceed our expectations, particularly, in the Northeast area of our acreage which is the farthest down dip. As you'll recall, we began our exploration program in the middle of 2018 with the drilling of the Phoenix state #1H which came in at approximately 2.8 million cubic feet of gas a day and 130 barrels of oil. We've been studying that area for about a year and a half doing work with Schlumberger, taking a lot of cores, doing a lot of work. We were a little surprised that we were that gassy as we've been projected to be in the oil window. So, we've moved down dip on the acreage to the Northeast area of our acreage which is the farthest down dip and we've drilled three additional wells down in that area. One well we reported on we drilled the Hippogriff #4H at the end of 2018. We completed it in early 2019. We are experiencing a water flow on that well that we believe is strictly due to mechanical issues I just wanted to make sure everybody understood that. We do not think, its reservoir related and that's because the -- even number 1H and 2H are immediate offsets to the Hippogriff and they did not have the same issue. So, while, we just have it shut in currently the Hippogriff well, while we have the engineering team, looking at ways to evaluate that well and figure out where this water flow's coming from. We think it may be possibly some -- a best in the job. But as to the two Hugin wells, we're very pleased with those as we reported in our operations update. One of the wells, IP-ed, Hugin number 1H, IP-ed at 818 BOE per day which was about 650 oil and around 900 gas. The other well the Hugin 2H came in at about 423 BOE per day. Both wells continue to perform very well, with stabilized production currently combined of about 600 barrels of oil per day and 1,000 Mcf. And that's because we've turned those wells down just a little bit, since they IP-ed to avoid excess -- pulling in excess sand into the wellbore. Both wells still have significant fluid levels, above the pump of 3,600 to 3,700 feet. So, we anticipate those wells and the production in those is going to hold up very well for a significant amount of time. The other two wells the Phoenix 1H and 2H are the up dip wells both very gassy. We have choked those wells back, at this time, due to the low gas prices especially in the Delaware Basin. As I'm sure, everybody's been reporting the pipeline capacity is extremely constrained for the Delaware. And it's causing at some points even negative gas prices in that area. So, rather than produce these reserves, at that price, we've just decided to choke those wells back. No, damage to the -- we're not anticipating damage to the reservoir or anything else. These reserves are not lost. They're just deferred at this time. On the CBP, the Central Basin Platform, we just have operations continuing as normal as Kelly pointed out. The wells that we've drilled so far, on the acreage that we acquired from Carlisle and a few other acquisitions there at the end of the year, we're seeing excellent results from those wells. We're very happy with that. On the Northwest shelf, we began drilling operations, as I said, on April 12, which was the day after closing of the Wishbone acquisition. To date we've drilled two wells and are drilling our third. First well has been fracked and should be on pump by this weekend. Obviously we will not see any significant contributions from these new wells until the end of this quarter and then, on especially into Q3 and Q4 as we really start getting more and more of these Northwest shelf wells online. One of the items in Kelly's report was the current daily production, which is down again slightly at 10,600 from Q1. And this is primarily caused by lack of activity on the Northwest shelf properties during the sales process. The last wells put on production came online, early, early Q4 of 2018. And there hasn't been any significant activity since that time. So obviously normal decline, has been in effect and -- but we anticipate that is going to turn around quickly, as we start seeing the new wells come online and should see significant growth from that area for -- especially in the second half of this year and on into 2020. A couple of additional points I wanted to get to. Our frac crew situation in -- when we went to one rig, we effectively lost control of our frac crew because it was spending more time away from us with other operators than it was with us, which caused some lumpiness in our completion schedule especially during Q1. Now that we've got two rigs running, we are back in control of the frac schedule. It only leaves -- frac crew only leaves when we say, it’s okay, so that should start evening out our completions as we move forward. Drilling costs, we are seeing everything staying in line. We don't anticipate any increases in our drill costs at least through Q2, Q3 and possibly on into Q4. We've actually been renegotiating some of our contracts. We're seeing no upward pressure at all to -- for prices to go up. So, we're very pleased to announce, that we think that's going to stay in line. Randy pointed out our op costs are -- should be coming down in the future. One of the drivers of our op cost is our vertical production. We have several hundred vertical wells that are legacy over from our initial days and startup of the company when we were drilling verticals San Andres wells, and then of course the acquisition of the Finley properties in 2015 which are now our Delaware properties. Significant -- both of those areas have a significant number of vertical wells which are higher -- have a higher LOE than our horizontal wells. So we anticipate over time, as the -- as that ratio of vertical to horizontal wells, goes down, that we should see a lowering of our LOE over time. We've had some questions about takeaway. The only place we're seeing any issues right now is on the gas side. We're seeing some sporadic shut-ins by the purchasers, as the pipeline capacities are an issue for them. But we do see that going away towards the end of this year and on into next year. The takeaway capacity on oil, I just got off the phone earlier this morning with our oil buyer. He sees no issues whatsoever. I asked him if anybody was seeing or hearing of anybody getting oil turned away or turned down, he said absolutely none. Those issues seem to be behind us. We don't anticipate anything and in fact our differentials -- we're seeing the spread on our differentials come back down into a normal range, which for us is usually around 5% of pricing. And so anyway we're very pleased to see that come back. And another nice point right now with the shut in of the Venezuela crude and some of the North -- Middle East crude not coming into the country, the sour barrels have come up to parity with WTI, which is very helpful for us. One other thing I'd like to point out on the gas side before I get away and hand this over to Hollie is that the gas stream is less than 10% of our income stream. So that gas price coming down hurts but it doesn't hurt us nearly as bad as it does some of the other operators that have higher gas production than we do. Now I'm going to turn it over to Hollie and she's going to discuss the type curves for the two areas now the Northwest Shelf and CBP and how they compare and she's also going to be going over the tiering that we did of Tier 1, 2, 3 and 4 and explaining that process and how we came up with that and we reported in our last update.

Thank you, Danny. Based on our press release that we released on April 29, 2019 in an effort to be fully transparent, we disclosed our internal tier work. And I'd like to walk you through it right now. It's pretty straightforward but I think it's worth basically addressing. So basically we took all of our acreage in our four core areas; Delaware, Central Basin Platform, North Gaines, and Northwest Shelf and classified them into a tiering system. Tier 1 would be our highest confidence wells. Those wells would represent our type curve production. And at $50 realized BOE price, they would reflect an IRR that's greater than 80% and net reserves higher than 325 MBOE. The PV-10 value would be approximately $4 million for each individual well. Our Tier 2 would be on par with Tier 1, but they are of more risk associated with these locations. They would be primary step outs to Tier 1 and would have similar rates of return that 80% and then reserves in that 325 area with a PV-10 of about $4 million. Tier 3 would be very commercial wells, but what we would consider to be under type curve. Their reserves would be in the high 200s low 300s. Their rate of returns would still be in that probably 50% to 70% range, but just not meeting the hurdles that we have set to classify Tier 1 and Tier 2. Tier 4 is I think the most exciting tier really to look at, because what it shows is the unexplored potential. When we made these acquisitions, we did our homework on subsurface, geology, core work, and we really cherry picked the acreage we felt had the most cost effective locations in these individual basins. The unexplored potential is we have yet to delineate if those Tier 4s are Tier 1s, Tier 2s or Tier 3s. So there is still a lot of upside in our acreage that we have yet to explore. About 55% of our Tier 1 locations were located on the Northwest Shelf. This was that accretive Wishbone acquisition we made earlier, but we have a strong Tier 1 locations in every basin. The Delaware has no Tier 4s simply because we've been working extensively on the geology in that area for as Danny mentioned a 1.5 years or two years and we have proven up a new producing horizon in that horizontal Brushy Canyon and the Hugin and Phoenix and Hippogriff wells. As it relates to the type curves in both areas, the Tier 1 criteria fits in both areas; the Northwest Shelf and the Central Basin Platform and the Delaware. We are seeing slightly higher IPs on the Northwest Shelf, a slightly lower decline and a slightly different B factor. But they are consistently hitting that Tier 1 criteria. At this point, I would like to turn it back to Kelly.

Before we turn that back to Kelly, let me just -- I'd like to point out one thing. Kelly had talked about during our-- during his section of the presentation was the CapEx. I wanted to visit here just briefly tell you the reason why we're looking at a midyear CapEx revision. Essentially I was on the Wishbone properties. We were essentially in control of the operations beginning in February. However, we did not physically get our hands on the wells until mid-April. And since that time, we've been working with the field people. We've been -- we actually hired the production manager who was over there at the time. We've been going over it with him, looking at different projects, different ideas that they have about some things we can do to optimize production as well as infrastructure and facility needs that we have moving forward. We are formulating a plan on that. I told Kelly and David I look at this like buying a new house. It's passed the inspection. You've gotten your closing done, but until you live in that house for a few months, you really don't know the intricacies or the little quirks about it that you need to -- that you always learn as you buy a new property. And that's kind of the way I look at this. We've got our hands on it now we've started to really dig in, look at the infrastructure needs, look at the work over opportunities. And so that's the reason why we are looking at a midyear CapEx update. And so moving forward with that, again I anticipate that will come out midyear and we'll be very transparent about what those costs are or what we -- the projects that we see needs for. And with that I'm going to turn it over to David to go over our acquisition opportunities.

Good deal. Thank you, Danny. So since the Wishbone announcement, we've seen a significant increase in the number of acquisition opportunities that have been brought to us since many of the operators in the area now see us as a platform and shelf consolidator. The majority of the projects we're seeing aren't in the public domain and range in size from smaller bolt-ons to several larger acquisition or acreage projects. Additionally, we continue to internally source acreage to net up our existing leaseholds and are focused on extending or bolting on acreage in our Tier 1 and Tier 2 core areas. As is our standard procedure, we take the time to review and evaluate each and every opportunity that crosses our desk to determine if there's a fit. But now that we have approximately 120,000 combined net acres on the CBP and the Shelf equating to a potential of over 20-year drilling inventory, our appetite's a lot more selective with a focus on add-ons that are meaningful and can be bought right. Regarding Investor Relations. To enhance our presence with new and existing investors, last year we started a more proactive role in attending and presenting at various energy and investor conferences. To date, we've have -- we've presented at many conferences across the country and have participated in numerous non-deal roadshows and plan to continue this pace going forward. And with that, Tim, I'll turn it back over to you for closing comments.

All right, David, thank you and hey, thanks everyone because I think you all did a really great job in bringing forward so much that we've accomplished and how meaningful and how impactful this is going to be going forward. It's going to be exciting. We've accomplished a lot in the last six, seven months and sometimes an adversity, but still we got it done. So congratulations to our team for doing a wonderful bang up job. So at this point, what I'm going to do as it concludes really our portion of the presentation of the review. So I'll turn it back over to Doug, our operator and we're going to open it up for questions that you may have. Doug?

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

Good morning guys, and great details today on the call. My first question, could you talk a little bit about -- I know Tim for you and Kelly you don't explicitly give quarterly guidance, but I just want to make sure to sort of help us analysts for the rest of the year and into next year, how do you think about as far as quarterly activity. I know Danny mentioned possible gas takeaway issues and I know talked to Danny in the past to off a deal for realization of prices and et cetera you ended up grouping some wells. So I'm just wondering could you talk about are there some lumpiness that we should be expecting? And how should we sort of think about that the lumpiness or the cadence for the remainder of the year?

Yes. Kelly, go ahead and then I'll comment as well.

Sure. Neal. We're combining these two assets together. We feel like we're going to be in that sort of plus or minus 20% range. It's like we had originally forecast when we were only looking at just the legacy assets. We still feel strong about that. We think we're going to be able to do that on a year-over-year basis. Obviously, as we're incorporating this transitional period here first quarter, second quarter we might see a little bit of lumpiness there, but it's continuing to smooth out and you can expect the second half of the year to look a lot better and to look a lot smoother and a lot more predictable. And I think everybody's going to be excited about it.

Yes. Neal, Kelly makes a great point and that is this. Look the activity that's taking place now in terms of adding that second rig I think Danny did a great job of articulating the movements behind that, but the reality of it is, is that second rig isn't really going to contribute at the earliest maybe the latter part of the second quarter. But I believe as we go into the third and fourth quarter kind of grab a seat, because I think it's really going to be impactful. So I think we're going to see some meaningful upswing at that point in time. We're certainly postured to continue that for some time to come.

And most of that activity at least for the remainder of this year on an either rig will focus on most of the Tier 1 activity that Hollie spoke of? Or will you venture and do some of the Tier 2 and 3 and potentially 4?

I think that everybody will tell you that we're going to focus on -- look Kelly mentioned it earlier, Danny mentioned it earlier, we've mentioned it numerous times. You know that we have a high priority of getting into cash flow neutral, a transition into cash flow positive and to do that we've got to cherry pick. We've got plenty. We could have 440 Tier 1 and 2 locations. Now it makes sense obviously that we'll step out occasionally to a Tier 3 or a Tier 4 maybe even more so on the Tier 4 side, but the bulk of what we're going to be doing between now and year-end is going to be Tier 1 and 2.

Okay. Then lastly by my math you all have interesting potential value built in some of your infrastructure let's call it your noncore upstream acreage. Just Tim have you and Kelly and the team talked about potentially monetization? Or I mean any thing you can mention towards potentially monetizing or the type of value you all see in the water and all of these other sort of EBIT noncore upstream assets you might have?

Certainly that's a great question Neal. And yes we've absolutely considered it and we've gone beyond considering it. We're really evaluating that now particularly -- if you look at the Delaware Basin for example that's a great asset and what we've done here to evolve with the Brushy Canyon, there's no question that that's a great asset that we could be developing for some time. However, as we've been mostly talking about here today between Wishbone and Northwest Shelf as well as the platform itself we're going to have plenty to say grace over. That's not to say that something's for sale, but we are evaluating that possibility and what that could be -- how that could be meaningful for us.

Very good guys. Look forward for all the activity. Thanks.

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

Good morning everybody. In your initial Wishbone presentation in early February you had it fried with a lot of details on the Wishbone infrastructure. And using Danny's analogy of moving into a new house, now that you've moved in, how are you feeling about the Wishbone infrastructure?

Danny call it?

You bet. John, look we're very happy with it. After sitting down with the manager out there, he had some very, very good points on some things we can do to increase reliability and redundancy in the system. And that's kind of what we're going through right now is what's it going to take for these -- for the existing facilities to be able to handle the drilling activity that we have moving forward. So that -- I think that's really kind of what we're talking about. We really kind of planning for the future drilling. But as far as the asset itself, we are very pleased with it. Everything is just what we thought we were buying, there's been no surprises. And the water heater hasn't gone out yet, but you never know. But no, it's everything is progressing just like we had hoped.

Well good. And you talked about your frac crew. That's the same frac crew that you've been using for about the last 18 months is that right?

That's right. It is Schlumberger and it's the same crew we've had now for about 1.5 years. And they know the process intimately now so it's -- everything runs very smoothly when they're on location.

All right, glad you got that nailed down. Congratulations on the deal. And I will turn it back to you.

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

Good morning everyone and thanks for taking my questions. So a lot of helpful information, a lot of things have been addressed. I apologize, if I missed this. But I was wondering what the current capacity is on your borrowing base and kind of a two-part outlook with that. How do you just think about your future liquidity outlook? I mean is there -- I think it was Neal who maybe hinted that some asset sales. I mean is that an avenue you could take? I know you mentioned free cash flow on the horizon. How soon is that coming? Just any color on future liquidity would be helpful.

You bet John. Let me respond and if Kelly would like to jump in he can as well. But let me start off by saying that, yes to Neal's earlier question as it's related to, specifically I think maybe midstream side of things and then possibly the upstream as well as we focus on the Delaware. That's certainly an asset that it's been suggested between ourselves. It's something that we've considered and it's certainly something that we're now evaluating and that is an opportunity to do something with that asset or assets and use that to further do some housekeeping as it relates to the balance sheet. As it relates to our current facility as you know and as we've reported, we now have a facility that's moved up to $1 billion, $425 million on the base. And with this acquisition, we're right now at approximately $350 million. As far as cash flow neutrality or ultimately transitioning into the cash flow positive side, we feel very comfortable is -- at a $50 realized price that we're going to get there by year-end.

Tim, what I would add to that is just a remainder in case there are some people on the call that don't realize this or may not know it -- we not only have a saltwater disposal system that is expensive out in the Reeves and Culberson County areas, we also have our own gas pipeline system out there. And then if you look up on the platform we own an oil pipeline system that is meaningful and substantial in value along with a substantial gas pipeline system and a saltwater disposal system that is larger than what we have out on the Delaware. And now we've bought the Wishbone assets we have two smaller saltwater disposal systems that once tied together would be a substantial system in that area. All of those items have significant value that we don't get credit for today of course and understandably why. But at the same time they do have substantial value. It's a very hot time for midstream companies right now looking for those types of assets. Again we're not saying that's something we're stepping up to, but it is something for us to keep in the back of our mind as we move forward.

Okay. Great, Tim, Kelly. It's really helpful. Just maybe to dig in a little bit more on the infrastructure because I definitely hear you there. I mean just -- I don't know if you could frame it for us maybe I don't know give us something to work with. Approximately how much EBITDA is running through those? Or how much volumes do you have either on gas, water, oil? Or just anything you could help us with just maybe to help us find some assumptions to come to some type of value ourselves. Thanks.

Kelly and Danny you want to start? Maybe Hollie you want to start with just kind of -- maybe a flat buy on the Delaware side?

Yes. Go ahead, Hollie.

Sure. So on the Delaware side -- on the saltwater disposal system, we're in the range of disposing between 40,000 and 45,000 barrels a day into an extensive infrastructure in multiple commercial SWDs that we all own and we own the surface so there's no royalties. So it's essentially royalty-free, which drives our price per BOE for disposal down into that $0.06-$0.07 range which is very economic. On the Central Basin Platform, we're in the neighborhood of disposing in the high 50,000 barrels a day into our own SWDs. It is a complex system which allows us to route water to different wells. In the Central Basin Platform there's a mixture of our surface owned -- and then some areas where we're basically paying a small royalty to the surface owner. Still very economic in that low $0.10 to $0.15 range for disposal and it's very extensive. On the Northwest shelf once again, it's very much like the Central Basin Platform. It's in the neighborhood of the low $0.50s to high $0.60s as far as disposal. It is also a combination of surface-owned facilities where we own the surface where the disposals are and then obviously there are some leases that we are disposing and paying a royalty on those waters. On the Central Basin Platform, we have an extensive oil system that goes into two separate black systems so we limit our trucking and we get -- we have a lot of advantages as far as the trucking cost because there is none and the marketing fees associated with that. That system ranges in the neighborhood of 10 miles north and south and about four miles east and west. So it ties a lot of our significant leases together into those two last points. We have an extensive gas system that ties on the Central Basin Platform to a DCP mainline basically removing constraints due to aged facilities. It is -- it's about 30 miles of gas pipeline that we have infrastructure that we own.

Okay. Great. Fantastic color. And just a point of clarification just circling back. I'm not sure if I missed it here or not but when -- is the expectation to get to free cash flow neutrality is that still by year-end 2019? Is that still the plan?

That's still the plan.

Okay. Great. All right. Well, thank you everyone. I appreciate the time.

You bet. Thank you.

Our next question comes from the line of Ron Mills with Johnson Rice & Company. Please proceed with your question.

Good morning. Now that you've had the properties at least in your hands now for almost a month I know it's still early. But maybe either for Danny or Hollie, can you talk about any kind of major differences you're seeing on the Northwest shelf versus your legacy CVP? I know there's different flow back methods and it's my understanding that the dewatering process up in the Northwest shelf actually can provide production benefits especially as you move through full development of a section. But any initial color on Northwest shelf versus legacy acreage?

That's a great question. Ron, there is a difference. What we see up on the Northwest shelf as you mentioned is that's an area that needs to be dewatered before you see the wells make their peak and come in with their maximum production. Now a lot of that obviously there's been a lot of drilling up in that area over the last four years or five years or so and so some of that has already taken place. In our presentation that we'll be uploading in the next few weeks, we'll talk about everything we've been talking about type curves. We will also be uploading some information that shows unlike some of the areas you're seeing with the Wolfcamp where you see this parent-child degradation issue going on we're actually seeing the opposite effect up in the Northwest shelf where the parent well is actually dewatering the area and the child wells are coming on stronger than the parent wells. We're seeing oil cuts faster. We're seeing higher peaks. And we're seeing, it looks like to us at least better EURs moving forward. We're going to present several slides within the presentation that will be looking at that going forward. But that's the main thing, we see up there. There are areas on the Central Basin Platform that need to be – have the pressures drawn down, before we see good oil cuts coming in. But it's not quite the same as we see up on the Northwest shelf. There's quite a bit of difference in the geology between the two. There's a lot more variability in the CBP. Just it was a much more active environment when the San Andres was laid down in there. We had this outlet sea going in and out and in and out multiple times. Whereas up on the Northwest shelf it was more of a backwater area the reservoir's much more consistent across the area. We've actually done some logging in there now that was kind of new to the area. So I won't get too deep in the weeds, but we've looked at the stresses is the completion we use down south where we actually look at the stresses within the rock. And we make sure that we perforate – within a stage we have perforations that have like stresses so that the wells – so all the perf clusters will break down at the same time instead of one breaking down and taking the entire frac. What we're seeing with the results on the Northwest shelf is that it's much more consistent up there. Like I said, it's laid down in a backwater kind of situation, it was kind of still. So we don't see all the variability in the stresses like we do down south which is very refreshing. And it should make for a much more consistent well and it could help us down the road on our – to help us to lower our completion cost as we decide whether or not we need to continue logging the wells and doing some things or just going to a straight geometric frac. So that's kind of the differences that we are seeing between the two areas. We're very happy with both, but we're really excited to get busy on the Wishbone stuff.

Great. And then as a follow-up, Hollie you did a good job walking through Tier 1 through Tier 4 and I think you're also referencing you're focused on Tier 1 and Tier 2. But when we think – as you start drilling some more of the Tier 3 and Tier 4, or as you sprinkle those in what are some of your bogeys that you're looking for to be able to transition some of those Tier 3 and Tier 4s? Is it based on production history? How much do you think you need? I guess, I'm trying to get a sense as to as we look out 12, 18, 24 months kind of how much of the Tier 3 and Tier 4s can kind of work their way up the ladder so to speak?

So that's a great question. No, I would like to see a six month production history really to start high grading some of those Tier 4s to Tier 1 and 2. In addition obviously when we're going out into these more unexplored potentials we will be doing some additional testing, logging to see if we can find that signature that helps us predict more consistently in these unexplored potential areas what's the signature that makes it that Tier 1 versus that Tier 2.

Great. Thank you very much.

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

Hey, guys. Sticking on the tiered inventory topic was curious if very – message received that your near-term focus is on Tier 1 and Tier 2. Do you have a sense if we look back on 2018 maybe how that I guess split may have been between the various tiers if we were to do kind of a look back on your 2018 development program?

Do you want to take that Danny?

Yeah. I would say one of the – obviously, one of the areas that we started out last year with is a Tier 4 area. It was our North Gaines area and there's still -- obviously there's still quite a bit of Tier 4 in that and that is the biggest area that we have Tier 4 in. However, the work that we did over the last year going in and working with the completion techniques and refining that and then now we're obviously getting the disposal well which is going to help the economics. That's just an example of one that we took from a Tier 4 to a Tier 1 or a Tier 2. That was one in particular. We did look at some areas, some outlying areas in – on the CBP that some of that turned from Tier 4 into Tier 2 probably and then a lot of it turned into Tier 1. But we did have a particular area in there in the north that we expected to do a little better. But I would say that's one that moved from a Tier 4 into a Tier 2 or so. So we have been sprinkling these in. We obviously to keep the growth growing you spend the most of your time drilling those good wells but then -- Brushy Canyon, let's look at that. There's a zone that was completely undeveloped in that area. I mean, we had some analogies that were miles away, but there wasn't a handful of those horizontal Brushy Canyon wells even up in New Mexico. And we took that from a tier -- I would say a Tier 4 and moved that to a positive Tier 1. So we are working on those and moving them in and we'll do that selectively during this year. There's quite a bit of area on the Wishbone acreage that needs to be looked at and the geology looks very promising. All the work we're seeing looks very promising, but you really need to get a well in there to move it up to Tier 1 or Tier 2. And you'll see us do that sporadically through the year.

Okay. Great. Really helpful context there Danny. For my follow-up. On the CapEx spending side, it looks like in the first quarter at least on a run rate basis you guys were kind of tracking I guess in line with the full year number that you've provided here recently, but obviously you have the second rig going for the remainder of the quarter. So could you guys just maybe help us kind of understand some of the gives and takes on the spending side, help us kind of I guess better setup our models in regards to spending profile for the remainder of the year?

Yeah. Danny, I think go ahead, address that. But keep in mind Jeff that again there's a lot of evaluation taking place between now and the next time that we bring that back to the Street for an update. But go ahead Danny and add some color, if you would please.

Sure. No, obviously, that's the thing. The update or the CapEx that we put out, we knew that was kind of -- what we knew about Wishbone plus our existing efforts on the Central Basin Platform and the Brushy Canyon. Knowing that we were going to need to do an update and there -- and obviously too with the additional the progress and the efforts we're seeing on the Brushy Canyon, there may need to be some infrastructure done there as we continue to watch those wells and if they hold up. There are some excellent opportunities in that, but we are going to need to do some work to be able to handle more water. Because the Northeast area that we're drilling, there was no infrastructure up in that part of our acreage. So, those are the things we're weighing back and forth. Our main goal though is to get to that cash flow neutrality. And so we've got to weigh those projects and see which ones have the most bang for the buck and get us to that point without overspending. So, it -- look, we'll be walking through that and particularly over the next couple of weeks and we'll have more clarity with that as we get to that mid-year point and start looking at the remainder of the CapEx.

All right. Understood. Look forward to that. Thank you. It sounds good.

Thank you.

Our next question comes from the line of Richard Tullis with Capital One Securities. Please proceed with your question.

Hey, thanks. Good morning, everyone. A question for Tim and Kelly. As you move toward the free cash flow situation late this year and then going into 2020, what's your preference for use of that free cash flow at that point? Tim, what's your comfort level with the current level of debt on the balance sheet? And would it -- would the excess cash going toward maybe relieving some of that debt? Or would you be open to share buybacks at that point, or what might be some other consideration?

Well, Richard, those are all fine points. There's no question that as we transition into the surplus side, the cash flow positive side, we'll be working on our balance sheet. There's no doubt about that. We're going to deleverage wherever we can, knowing that there's no capital market that exists for us or anyone else for that matter for right now probably for some time to come. So, we are focused on what we can do with assets that may not be as larger contributor as they've been in the past, particularly now when you compare it to what we've done with these recent acquisitions. So we'll be looking again at that side which we've touched on a bit earlier. But as we transition into that surplus cash, there'll be one or two things. It will be cleaning up that balance sheet and considering acceleration which at these multiples will continue to just benefit the value of the company. So will we consider share buyback? Look, there's no question in our opinion. Everyone on this team realizes that -- and I think a whole lot of you folks realize that right now these shares are grossly undervalued. No question about that. I don't care what model you want to use -- you take a look and you can argue whether it's the EBITDA side or NAV side or maybe a couple of others. There is no question that it's undervalued. So why doesn't the company stop and start buying shares back? The dry powder that we have, the liquidity that we have, we are best at our job and managing that to continue to add growth and bring that cash flow neutrality and eventually that positive surplus build to the bottom line. And then, on the way, with some of these other ideas and then with the surplus cash, start deleveraging and then look to accelerate.

Thanks, Tim. That’s the only the question I had. I appreciate it.

You bet.

There are no further questions in the queue. I'd like to hand the call back to management for closing comments.

Okay. Thank you, Doug. We appreciate it. And thank you everybody for taking the time today. We know there are a lot of companies that are reporting and we appreciate your support. If you have follow-up questions, feel free to reach out to, of course, Bill Parsons, Investor Relations and we'll always have that open door policy. We want to be able to have communication as often as you'd like. Thanks. Have a good day.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.