Earnings Call: Q2 2019

Aug 8, 2019

Greetings and welcome to the Ring Energy Inc. Conference Call to discuss the twenty nineteen Second 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. As a reminder, this conference is being recorded. I would now like to turn the conference over to our host, Mr. Tim Rochford, Chairman of the Board of Directors. Thank you, sir. You may begin. Thank you, operator. And I'd like to thank and welcome all listeners for joining us today on our twenty nineteen second quarter and six months financial and operations conference call for Ring Energy. Joining me on the call today, in addition to myself, again, Tim Roger, Chairman of the Board, will be Kelly Hoffman, our Chief Executive Officer David Fowler, our President Randy Broderick, our Chief Financial Officer Danny Wilson, Executive Vice President of Operations Holly Lamb, Vice President of Engineering and of course, Bill Parsons, who joins us from Investor Relations. Today, we'll cover the financials and the operations of the second quarter and six months ended June 3039. We will review our results and provide some insight as it relates to the current progress thus far in the third quarter of 'nineteen. At the conclusion of the review, we'll turn the call back over to the operator, and we're going to open up for any questions that you may have. Now I'm going to ask Randy Broderick to give us a review on the financials. Randy? Thank you, Tim. Before we begin, I would like to make reference that any forward looking statements which may be made during this call are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued Wednesday, 08/07/2019. If you do not have a copy of the release, one will be posted on the company website at ww.ringenergy.com. For the three months ended June 3039, the company had oil and gas revenues of $51,300,000 and net income of $12,400,000 as compared to revenues of $29,900,000 and net income of $4,700,000 in the 2018. For the six months ended June 3039, the company had oil and gas revenues of $93,100,000 and net income of $23,500,000 as compared to revenues of $59,800,000 and net income of $10,400,000 For the three month period of 2019, the net income includes a pretax unrealized gain on hedges of $1,500,000 acquisition related costs of approximately $600,000 and a deferred tax benefit adjustment of 600,000 Without these items, net income would have been approximately 11,600,000.0. The three month period of 2018 net income includes a pretax unrealized loss on hedges of 1,100,000.0. Without this item, net income would have been approximately $5,600,000 For the six month period of 2019, the net income includes a pretax unrealized gain on hedges of $1,200,000 acquisition related costs of approximately $4,100,000 and a deferred tax benefit adjustment of 4,500,000.0 Without these items, net income would have been approximately $21,300,000 The six month period of 2018 net income includes a pretax unrealized loss on hedges of $1,900,000 and an additional tax provision of $1,200,000 Without these items, net income would have been approximately $16,300,000 For the three months ended June 3039, our oil price received was $56.86 per barrel, a decrease of 8% from 2018, and our gas price received was $0.95 per Mcf, a decrease of 69 percent from 2018. On a per BOE basis, the second quarter twenty nineteen price received was $51.95 a decrease of 9% from the 2018 price. For the six months ended June 3039, our oil price received was $53.74 per barrel, a decrease of 12% from 2018. And our gas price received was $1.51 per Mcf, a decrease of 53% from 2018. On a per BOE basis, the price received for the six months ended June 3039 was $51.95 a decrease of 9%. And I'll double check that. I apologize. Production cost per BOE for the three months ended June 3039 decreased to $11.71 as compared to $12.7 in 2018. Production costs per BOE for the six months ended June 3039 decreased to $11.24 as compared to $11.97 in 2018. We are still evaluating the ultimate impact the Wishbone acquisition will have on our ongoing production cost per BOE, but we expect it to be at or below our historical average. Most production taxes are based on values of oil and gas sold, so our production tax expense is directly correlated to the commodity prices received. Our production taxes as a percentage of revenues remained relatively flat and should continue to be. Our total depreciation, depletion and amortization, including accretion of asset retirement obligation, per BOE for the three months ended June 3039, decreased to $15.02 per BOE as compared to $17.81 per BOE for the same period in 2018. Our total DD and A per BOE for the six months ended June 3039 decreased to $14.99 per BOE as compared to $17.32 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, our DD and A increased by approximately 59% for the three month period and approximately 56% for the six month period ended June 3039, versus the comparable period in 2018. Our overall general and administrative expense increased $1,700,000 for the three months ended and $5,600,000 for the six months ended June 3039, as compared to the same period in 2018. However, we incurred approximately 4,100,000 in acquisition related costs during the six month period, of which approximately $600,000 was during the three month period. Without these additional costs, the increases from 2018 are approximately $1,200,000 for the three month period and $1,500,000 for the six month period. Excluding the acquisition related costs, on a per BOE basis, this equates to an increase from $3.59 in 2018 to $3.96 in 2019 for the three month period, and a reduction from $6.1 in 2018 to $4.12 in 2019 for the six month period. Second quarter twenty nineteen development CapEx was approximately $51,000,000 Along with the approximately $46,000,000 from the first quarter of 'nineteen, this puts the six month development CapEx at approximately $97,000,000 These amounts exclude acquisition related costs and the incursion or assumption of asset retirement obligations. On a per Boe basis sorry, on a diluted basis, rather, the income per share for the three months ended June 3039, was $0.18 as reported. Excluding the $600,000 deferred tax benefit, the pretax unrealized gain on hedges of $1,500,000 the 600,000 acquisition related costs included in G and A and the $809,000 noncash charge for share based compensation, the income would have been $0.17 This is compared to income per share of $08 as reported or $0.13 per share excluding the $1,100,000 unrealized loss on hedges, the 2,400,000.0 pre tax realized loss on hedges, and the 1,000,000 non cash charge for share based compensation in 2018. For the six months ended June 3039, the income per diluted share was $0.36 as reported. Excluding the $4,500,000 deferred tax benefit, the pretax unrealized gain on hedges of 1,200,000.0 the $4,100,000 acquisition related costs included in G and A and the $1,600,000 noncash charge for share based compensation, the income was $0.34 This is compared to income per share of $0.17 as reported, or $0.24 per share excluding the $1,900,000 unrealized loss on derivatives, the $3,900,000 realized loss on hedges, and the $2,100,000 noncash charge for share based compensation in 2018. As of June 3039, we had 3 and $60,500,000 of the $425,000,000 borrowing base drawn on our credit facility, and had cash on hand of $10,600,000 For the three months ended June 3039, we had adjusted EBITDA of approximately $33,300,000 or $0.49 per diluted share compared to approximately 17,300,000.0 or $0.28 per diluted share for the same period in 2018. For the six months ended June 3039, we had adjusted EBITDA of approximately $57,500,000 or $0.87 per diluted share, compared to approximately $36,500,000 or $0.61 per diluted share for the same period in 2018. With that, I will turn it back to Tim. All right, Randy. Thank you. Appreciate that. I'm going to ask Kelly to give us a recap on the second quarter overview and operations. Kelly? Thanks, Tim, and thanks, everyone, for joining us on the call. In the three months ended June 30, the company drilled 13 new horizontal San Andres wells. Our Central Basin Platform asset, we drilled seven new horizontal wells, five one mile horizontal wells and two one point five mile horizontal wells. And on our newly acquired Northwest Shelf property, we drilled six new horizontal San Andres wells, four one mile horizontal wells, two one mile point horizontal wells. And we're in the process of drilling two more at the end of the quarter. Of the 13 wells drilled, four were waiting on completion. That was two Central Basin Platform and two Northwest Shelf wells. Seven were drilled, completed and are in various stages of testing, five on the Central Basin Platform and two on the Northwest Shelf. And two were drilled on the Northwest Shelf, completed, finished testing and had initial potentials as filed. The first one was the Bruce E. Gentry Jr. 647A2H. It had an IP of three fifty nine barrels of oil equivalent per day. That calculates to 88 BOE per 1,000 foot. And the sooner six sixty two with the second well, A2H, and an IP of seven sixty seven barrels of oil equivalent a day, which is 181 BOE per 1,000 foot. We're very pleased with the preliminary results we're seeing on the Northwest Shelf and the continued results we're seeing on our Central Basin Platform assets. All our forecasts are based on average type curve IPs of 86 BOE per 1,000 foot and the average IP on all of our horizontal wells continues to exceed 100 plus BOE per 1,000 foot. As a result, net production for the 2019 was approximately 976,000 BOEs That equates to about 10,725 BOE PD. That's on a per day basis. This is the first time the quarterly operations update combines both the Ring and the newly acquired Northwest Shelf properties. June 2019 average net daily production was approximately 10,800 BOEs per day. A side note for the listeners on the call today, want everyone to know that we had previously reported, if you'll remember, a differential of approximately $5 per barrel and however July came in at $3 and when we're looking at the snapshot of August up to this point, it is also looking like around $3 maybe slightly less going forward here. We're feeling pretty strong about that. So with that, I'm going to turn it over to Danny and Hollie to give you some current update on operations and a little more detail on our plan moving forward. Thank you. All right. Thanks Kelly and thanks everyone for being on the call. I want to start out by giving you an update on a few of our existing wells. Out in the Delaware Basin our Brushy Canyon horizontal wells continue to have impressive production, in particularly the Hugin 1H and 2H, which are located in our Northeast part of our acreage. They continue to produce at a combined rate of three fifty barrels of oil per day and 2,300,000 cubic feet of gas. Since the beginning of the year, these two wells have combined production of over 105,000 BOE of which 80% is oil. On our North Gaines acreage, our two horizontal San Andres wells, the LMP Peters number 3H and 4H continue to produce at a combined rate of 150 barrels of oil per day. To update you on our Q3 activity, we are currently drilling our sixth and final well of the quarter. We should be finishing it up by the middle of this month. All the wells drilled this quarter as well as those planned for next quarter have been drilled on our newly acquired Northwest Shelf acreage. We are drilling this area for two reasons. The first being that we have fulfilled our drilling obligations on the Central Basin Platform for the year and the second reason is due to the early results we are seeing on the Northwest Shelf. As Kelly mentioned, our first two wells on the Northwest Shelf IP'd at three fifty nine and seven sixty seven BOE per day. Results like this are exactly why we bought the Wishbone acreage. The acquisition checks every box we're looking for in a project area. It's a conventional reservoir with a dolomite that's a dolomite and not a shale. It's at a shallow depth of approximately 6,000 feet. It has low development costs and yields high returns. And most importantly, it has plenty of running room. As pleased as we are with our CBV properties, we're even more encouraged by the early results we are seeing on the Northwest Shelf. And that is why we plan to do the bulk of our drilling in this area over the next year. Just to be clear, we are drilling on the Northwest Shelf because the results are exceeding our expectations and we have fulfilled our obligations for the year on the CBP. I also want to walk you through the thought process behind the changes we have made to our 2019 capital spending budget, which we announced in late July. Our main focus was on three key points as we worked through the revised budget. First, we were concentrated on obtaining cash flow neutrality as quickly as possible. Secondly, we were managing our debt. And third, maintaining modest year over year growth. After closing the Wishbone acquisition in early April, we released a preliminary budget of $154,000,000 which included the drilling of 50 horizontal wells for the year. In the same breath, we reiterated that this was a preliminary budget and that once we had a chance to operate the properties for a few months, we would release an updated budget which would likely be higher. Our internal estimates were that we would likely have an increase of around 15%, which would raise our spending for the year to $175,000,000 to $180,000,000 Once we took physical control of the properties, we realized there was an even greater backlog of opportunities that needed to be addressed. This was largely due to the lack of capital spending by Wishbone while they were marketing the property and subsequently closing the sale. This lack of spending occurred over a six month period from October 2018 until the close in early April of this year. Once we evaluated the work that needed to be performed, we realized that most of the work fell into four main categories. The first was the need to perform workovers on wells which were shut in or had reduced production due to scale, iron and sand accumulation in the wellbore. Second, we had wells with ESPs which needed to be properly sized. Third, we had wells which needed to be converted from an ESP to a rod pump. And fourth, infrastructure projects to increase electrical reliability and the streamlining of the wastewater handling systems to allow for future drilling activity. As we completed our project evaluation, we could see that if we were to move forward with the original drilling program and perform the additional work we had identified that the budget was going to increase substantially beyond the anticipated 15%. At that time, we took a step back and looked at our options. We can move forward with the original 50 well drilling program and further increase our budget over the anticipated 15%. However, this could have jeopardized reaching two of our three goals that of getting to cash flow neutrality and managing our debt. Or we could go with the second option and scale back the drilling enough to maintain modest year over year growth, get our house in order by working over wells, rightsizing our production equipment either through downsizing of ESPs or converting to rod pumps where possible. We chose the latter option to ensure that we could meet all three of our stated goals. I'm going to turn the discussion now over to Holly Lamb, our Vice President of Engineering, and she's going go through the reasons and the economics behind performing these workovers. Thanks, Danny. I'd like to focus on the economics of the workovers and optimization. Let's start with the workovers. The workovers are associated with some type of downhole obstruction in the lateral portion of the wellbore. These downhole obstructions are not predictable. They cannot be scheduled, and they don't happen on every well. They can be identified by various means, including changing in their production profile. They can consist of a combination of frac sand and scale, and that scale can be either iron based or calcium sulfate. Based on our experience, these occurrences involving scale obstructions are a single event occurrence in a wellbore history. These events happen early in the well's life and are generally associated with the maximum pressure drop from the higher pressure formation to the lower pressure wellbore. These materials can be mechanically drilled out of the wellbore, and then the wellbore can be chemically treated. In many cases, these wells return to a normal production profile after the intervention has taken place. But in some cases, the production actually exceeds the previous profile. In both areas, we have seen rates of return in excess of 100% with payouts of less than one year. These compare very favorably with our metrics on our new drill wells. Let's switch gears now and talk about optimization, specifically optimizations of our pumping equipment. Early in the life of a well, we install an electric submersible pump, or ESP, which is sized to move 3,000 to 4,000 barrels of fluid a day. As a well naturally declines, it makes sense to change out these ESPs to smaller ESPs, reducing the horsepower draw, electrical demand, and also extending the run time of the pump since it reduces the wear and tear on the right sized pump. Eventually, these wells will decline to a point where it makes sense to replace the ESP with a rod pump. Once this occurs, we see tremendous benefit. The continued reduction in LOE as much as 50% due to electrical usage. But we also have substantial reduction in equipment maintenance as well, since now most of the pumping equipment is located on the surface as opposed to being downhole. The aforementioned benefits are eclipsed by the reduced cost on pulling these wells going forward. A typical pulling job for a repair on an ESP runs around $200,000 to $250,000 A typical repair job on a rod pump is between 20 and $40,000. This translates into an 80% reduction every time we work on that well. The initial conversion to rods cost between $150,000 and $250,000 This translates to an LOE savings every month and a lowered cost on well servicing going forward. This conversion pays out the first time we pull a well. The lower LOE extends the economic life of the well and by extension adds economic reserves. Based on these benefits that we have laid out for both the workovers and optimizations, there is no doubt this is the right decision and will return dividends tomorrow and for many years to come. At this point, I would like to hand it back to Danny to wrap up the operational update. Thank you, Holly. To recap our budget discussions, we started with three key goals. First, reaching cash flow neutrality as quickly as possible. Second, managing our debt. And third, still maintaining modest year over year growth. In early April, we took over physical control of the Wishbone property. We immediately started drilling on the property and issued a preliminary budget. We analyzed the properties, identified the opportunities in four key areas. First being the working over of underperforming wells second, rightsizing of existing ESPs to lower cost third, converting to rod pumps where possible thereby reducing lifting cost, which yields increased EURs and most importantly drastically reduces future pulling cost, which ultimately reduces future CapEx and future LOE. And four, performing infrastructure projects to streamline water handling and facilitate future drilling. And finally, late July, we issued a revised budget, lowered which our CapEx and greatly increased the certainty that we could meet all three of our key goals. And with that, I'm going to turn it over to David to cover our leasing and merger and acquisition discussion. Thank you, Danny. As you are all aware, we've had an active and exciting second quarter with the acquisition of the Wishbone assets that was truly transitionary for Ring as it doubled the size of the company. The assets were a perfect fit for our core asset base and established Ring as a consolidator on the platform and now on the shelf. Besides being a great acquisition for Ring, we were able to buy the assets during a distressed oil market or what we refer to as a buyer's market for a price that was essentially a PDP value. In short, this asset is going to provide Ring and our shareholders a lot of value and growth for years to come. Regarding our leasing, since we now have an acreage position on the platform and shelf of almost 120,000 net acres, our leasing activity is somewhat limited and more concentrated in a few target areas on both the platform and the shelf that is mostly focused on grossing up our net acreage positions, offsetting our upper tier locations. The land department has done an excellent job of simulating the Wishbone leases into our system while they work diligently to stay ahead of operations and the drilling rig program. Regarding A and D, since the beginning of the year, numerous companies have taken their assets to market across the Permian and elsewhere and have had failed sales indicating that we're still in a retracted A and D market. The bid ask from buyers and sellers continues to be significant enough to make it difficult to get deals across the finish line. Hopefully soon, we'll see the market conditions improve and we'll see the door open to more M and A activity. With our ongoing effort to differentiate ourselves from the non conventional shale operations in the Permian or operators in the Permian, what I refer to as being in the shadow of the shales, we're attending several conferences and NDRs between now and the end of the year to tell our story. I hope that I'll see a lot of you there. And with that, I'll turn it back to Tim for closing comments. All right. Thank you, David. And Danny and Holly and Kelly and Randy, good job, guys, reviewing everything. So now I think what we'll do is just turn it over to the operator because this will now officially conclude the twenty nineteen second quarter and six month review. So operator, I'll turn it back to you, and let's open it up for questions that they may have. Thank you, sir. At this time, we will be conducting a question and answer session. Our first question comes from John White with Roth Capital. Please state your question. Good morning and congratulations on a very solid quarter. Thank you, John. I really appreciated Holly's detail on the workovers and the pump optimization. That was great great new information. So now you're on a one rig program, and you're gonna do a lot of rework and refurbs on existing wells, you say, on both the Northwest Shelf and the Central Basin. Do you have a split of how that how how many on on each of those properties? In terms of the workover and the rod conversions? John, is that Yeah. Can What's the workover split between the shelf and the Central Basin? Yeah. Danny and Paulie. You bet. John, that's great a question. It's really almost about a fifty-fifty split. So there's not either area that really is outshining the other as far as what needs to be done. Again, the main focus on the Central Basin Platform is the rod conversions. Those are little older properties. They've been producing longer and we're diligently working on getting those converted over. Up on the Northwest Shelf, it's more of a combination of the two things well three things, the ESPs making sure those are the right size, cleaning out the well bores and returning those to production and then the rod conversion. So the money is pretty evenly split but there's a little bit of difference between the two areas as far as the work that's being done. I appreciate that. Makes sense on the Central Basin going to mostly rods due to the age. And then, Kelly, did you mention what production was during the month of July? No, I did not. John, I think what was referenced in July was the differential that we were seeing for July. It was. Our next question comes from Jason Wangler with Wunderlich Securities. Good morning, guys. You mentioned in the prepared remarks about moving to the Northwest Shelf the rest of this year. As you look at the program, if it's a one rig program next year, could you maybe talk about how you kind of see the activity between the two properties? Sure. Danny, you guys want to grab that? Yes, you bet. Now down on the to start out with on the Central Basin Platform, the focus most of our drilling is focused in the area that we recently purchased from Tesara on University Lands acreage down there. We did that acquisition right before the Wishbone acquisition. With the University Lands, we have a minimum footage that we have to drill. So next year it looks like we're probably going to need to drill about eight to nine wells down there. And so that's what we'll do in that area and then the rest of the wells. And we haven't come up with a final number yet but it's probably going to be in the 30ish range. Includes the eight wells on the CBP. But something in that range will probably be the remainder of those will be up on the Northwest Shelf. Okay. I appreciate it. Thank you. Our next question comes from Neal Dingmann with SunTrust Robinson Humphrey. Please state your question. Good morning, Neal. Tim, maybe for you or Kelly, I mean, don't need anything too specific here. I'm just wondering, could you give sort of how you all view the magnitude or list the potential of the noncore asset sales? And I guess where I'm going with that is I'm just wondering sort of general levels if some sale maybe once you give that answer, how that might play into if you would think about going to a second rig or so because obviously, you're obviously very cognizant of as you should be of not going too high on the debt. So just wondering based on what you tell us the magnitude or potential timing of these other noncore sales, the second part of that question would be how that could play into potential second rig for the program sometime next year. You bet, certainly. Well, there's no question. Between the platform and now the Northwestern Shelf, we have plenty to do for years to come, even with if you were to deploy multiple rigs. So that reshifts the focus back to, well, what about Delaware? The Delaware is a fine asset, but really it has taken second or third place in terms of the line items of priority. So one would seem to think is that an opportunity to possibly move off and improve the balance sheet, add some cash available for future acceleration, etcetera, etcetera? And the answer to that is likely, yes. But there's no official marketing effort at this time as it relates to the production profile. There has been some thought given to the midstream on the SWD side. In fact, we've had conversations with interested parties, but we've done nothing yet as an official move. But that's something we do keep in mind as we go forward. And you're right, Neil, there 's two things that would become of that. One is to improve or tidy up the balance sheet and the second, provide a cash cushion, if you will. If, in fact, commodity space improves as we go into next year, accelerating to a second rig would certainly boost that opportunity. Pretty good. And then just one last one probably for Danny or Holly. You gave a good list of the reasons for the workovers. And like John, I appreciate that. I'm just wondering I mean, I think some thought, you know, for Kelly, for any of you all, that this was more of a regular item. And I'm just wondering if you could just talk about, as you see kind of on a go forward starting next year and so when you think about workovers, is this just more on a case by case basis? Is this something that you'll think you'll need more often than not? Maybe if you could just sort of explain that to us, I think that would help. Thank you. Neil, that's a good question. One thing people tend to forget is that we operate over 700 wells. It's not just these few that we continually talk about. So there's always projects to be done. There's always going to be a certain amount of our budget that's going to be allocated to working on existing wells. And so moving forward, there's always going be projects. We don't really ever know typically when a well is going to go down and need to be worked on. Do I think it's going to be this magnitude? Possibly. But it's not probably not as much though because we did have a big backlog that we had to deal with and are still dealing with moving forward. But I think we'll largely have that handled by the end of the year. Moving into next year, things should I think the pace will slow down and even out a little bit more. And if I could sneak one last one. And then just based on sort of CapEx, know I you certainly don't have Tim, you and Kelly don't have any guidance out for future CapEx. But I'm just wondering if from broad terms, when you think of either I'll throw workovers into potentially non D and just non typical D and C as I would infrastructure, how would you think about the non D and C spend next year versus this year? I got to think it's going to be it would be down a bit. A bit is right on. I don't think there's any question. I think Danny did a good job of saying, listen, Between the backlog that already started to build on the platform and along with the backlog that came along with the inheritance of the Wishbone because of just, you know, no activity for a number of months, that is a bit overwhelming, but it's very manageable. Once we catch up with that, as Danny said, I think as we go into next year, and as Holly carefully pointed out, you can't always predict the timing of this, and it doesn't happen to every well. So I think next year, there's no question as we put out our CapEx, there's going to be a healthy line item for that type of activity. But I don't think it's going be anywhere near to where it's at today in terms of ratio versus drilling and completion. Great. Thank you all. Our next question comes from John Lane with Lane Capital Markets. Please state your question. Hey, Ken. How are you? Good, John. Congratulations on a fantastic quarter. I'm sure that everybody on this call is smart enough to understand that the stock price is nowhere relevant to what's going on internally with the company and the tremendous assets built here or continuing to build here. Can you just discuss a little bit about why you think the price of the stock is getting hurt as bad and maybe a little discussion in regard to some of the insider buying that's been taking place that doesn't seem to hit the press anywhere? Yeah, you bet, John. I'd be happy to remark on that. I think I'll start off by letting Kelly address that, and then I'll follow-up. Thank you. No, John, appreciate it. Look, there's no question that there's been sort of an increased level of shorts and things that are out there in the marketplace. And we've taken note of that and we've started to talk internally about it. We've even had some conversations with outside people, but not to a point where, of course, it would be any type of distraction for us. We're maintaining our focus on getting to those items that Danny was talking about and the free cash flow and all that. But we do keep an eye on those things and we are taking aggressive approaches to it to the extent that we can. And I would say that going forward, I think the combination of that along with some computer selling and some things like that, we've probably been a bit of the victim for that. I would say that looking at us this year, we've taken a lot of aggressive approaches to cost management, to concepts like this revision on our budget was a very aggressive approach to again protecting the balance sheet, getting us the cash flow neutrality and still showing growth. We're listening to the Street closely and we're trying to pay as much attention to those items as we can and be very careful and thoughtful about our approach. And John, just as a follow-up with reference to your question. So as you know and as everyone on this call knows, there are times in the life of management in the company during the course of a year that we have our lockouts or block out periods when it really prevents us from being active at all in the stock. That was a considerable amount of time that took up last year. And and the same is the kind of the case this year. We did have some insider buying, as you know, just a number of weeks ago, and then that window closed very quickly. I won't I won't elaborate on that. But as David Fowler mentioned in his comments, there are a number of opportunities out there on the platform and on the shelf, and we look at these. And anytime there's any discussion, we're very careful from our own internal policies. We're very careful with reference to our own personal activities pertaining to the stock. So right now, there is just absolutely no question where this stock trades versus our peers. I follow probably 35, 40 different companies pretty closely. And I think you'll look and see that 80%, probably closer to 90% of those companies are all trading at fifty two week lows. Of them beat up more than others. And we fall into that category. But there's no question that this stock, in our opinion, is grossly undervalued for a number of reasons. And you can do the metrics and figure that out. So whether you're doing multiples or you don't want to throw out the old NAV style of valuation, fine, throw it out. But look at the multiples. Look at the projected. Just imagine what EBITDA can look like based on this last quarter going forward. So you start doing some multiples of that. You look at the production profile. I think everyone would agree that even in the absence or factoring in the debt component that it's screaming by. But enough of beating that drum. I hope that answers your question, John. Yes. You've always been a shareholder focus. And I know that's never going to change. And I know that sooner or later, the stock price will catch up to what you really got going. I just appreciate your constant effort to make this company stronger and better. Thank you. Thank you, Kelly, too. Thank you, John. Our next question comes from Mark Levy. Please state your question. Thank you. I appreciate the opportunity. Based on the conversation where the Delaware Holdings have slipped to a second or a third degree priority and mitigating debt is an issue. Is there a general sense of the valuation of that Delaware Basin holding generally? Danny, you might want to reflect on that or Kelly. I think we can all kind of have our opinions of that. But we haven't just let me start off by saying this, Mark. We haven't formally started sitting down drawing circles in terms of where we think, what kind of values. I think we all have ballpark values where that might be. And I don't think we're going to, in this discussion today, talk about those numbers, but maybe kind of giving an overall feel of things, maybe, Danny, you can take the first swipe at that. Well, obviously, we're very happy with the area out there. We love the potential for the horizontal Brushy Canyon. We think that has tremendous upside. Unfortunately, it's hard for that area to compete for the dollars when we're looking at the returns we're seeing over on the Northwest Shelf. Although they're similar, it's still a little bit different. As far as the value of that, I don't know that we really have a feel for what the market value might be. Mean, internally we have reserve values on it, obviously. But the market's been all over the place. With that, I'll let Kelly comment. I was going to add that when we talk about that asset out there, people tend to think of it from just an oil and gas standpoint. And frankly, there's a substantial asset out there on top of it. It's called our solar disposal system, which we have done a great job of building. Holly and Danny have done a wonderful job with the troops of building that from north and south creating multiple redundancies. And frankly, we've had people from a private equity standpoint come into our office a number of times over the past two years, actually maybe a little longer than that. And they turn around a lot of different numbers, Mark. I I don't know what the value of it is today. A couple of years ago people were tossing around $20.30 and $40,000,000 numbers. I couldn't guess at what it would be today, but I do believe it would be additive to the concept of the oil and gas sale if we did decide that it was something that we could market or someone came into the office and threw something at us that really we couldn't pass up as an idea, it probably would include an upcharge, so to speak, for that system. So we're hopeful that that maintains that capacity going forward, and we'll see what happens. Fair enough. Thank you. The only other question I have, and it's probably not fair and it's across all strata, is there an average general decline curve that would be generally considered appropriate? I know that's For not there, I'm the company? Yeah. Danny Holy? You know, we do have the type curves out on our website for each area. So I would just suggest that you look at that. Fair enough. Fair enough. We don't really have a combined company wide one. Okay. Thank you. Our next question comes from Richard Tullis with Capital One Securities. Please state your question. Thank you. Just one or two quick questions, maybe more for Danny. What's the outlook given the one rig and the planned workovers and swapping out of the pumps? What do you expect the production exit rate 2019 could look like Danny? And then continue with one rig into 2020, what do you expect the production growth profile could look like next year? Yeah. I think Richard, I think internally we're kind of looking at a number in the mid $11,000 be a little higher, could be a little lower than that for our exit rate for this quarter. Obviously drilling fewer wells is going to as I've mentioned in my report, we're going to we're trying to go for modest growth, but the key focus is still on getting cash flow neutral and managing the debt. So I would say that and then I would think next year you could probably look at anywhere from a 3% to 8% increase, something in that range. It's kind of the that's what our models are indicating. And that would be based on one rig, Danny? That's based on one rig. That's helpful, Danny. And then just lastly, maybe for Tim or Kelly. You've stated the target of the free cash flow neutrality by year end this year. Does that hold for next year as well for the full year? It does. Okay. All right. Well, that's all for me. Thanks so much. Thank you, Richard. Thank you. Our next question comes from Ivan Zwick. Please go ahead with your question. As a follow-up to the gentleman that asked the question about the stock price, can you tell me what the net asset value per share of the company is? The net asset value? Are you basing that on the PV-ten of total proved? Yes, right. Okay. So Randy, do you have that handy? Or maybe Holly, you have that handy? Total proved combined assets. Randy? Give me just a moment. Okay. Ivan, just to be certain, you're making reference to 1P and not 3P. Is that correct? I guess, right. I think the stock price is pretty ridiculous myself. We would agree. When you look on our website, I think we have a slide. It seems like it's maybe number 24. And I think it's in and around that $1,100,000,000 range, if I'm not mistaken, on a PV-ten basis. Okay. Don't have that handy. Do you? Okay. I was going to add that you want to give consideration to the stock price, of course, when you do that. So I'm sure there's a footnote there on that page which refers to what we used in that calculation. Okay. And I thought you'd have a fine quarter. To hear. Thanks, Ivan. Thank you, ladies and gentlemen. There are no further questions at this time. I'll turn it back to management for closing remarks. Thank you. Okay. Thank you, operator. We appreciate it. And thank you, everyone, for taking the time. We know, again, it's that busy time of the year with a lot of reports from a lot of other companies having their calls as well. So thank you. And as always, our door is open. And of course, Bill Parsons, Investor Relations is happy to hear from you. And we'll look forward to talking to you along the way. Thank you. Thank This concludes today's conference. All parties have disconnected. Have a great day.