Earnings Call: Q3 2019

Nov 7, 2019

Greetings, and welcome to the Ring Energy twenty nineteen Third Quarter and Nine Month Financial and Operating Highlights Conference Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Tim Rochford, Chairman of the Board of Directors of Ring Energy. Please go ahead, sir. Thank you, Kevin, and good morning, and welcome to all listeners for the twenty nineteen third quarter and nine month financial and operations conference call for Ring Energy. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call this morning is our Chief Executive Officer, Kelly Hoffman our President, David Fowler Chief Financial Officer, Randy Broderick Executive VP, In Charge of Operations, Danny Wilson Holly Lamb, our VP of Engineering and Head of Investor Relations, Bill Parsons. Today, we're going to cover the financials and operations for the third quarter and nine months ended September 3039. We will also review our results and provide some insight as to the current progress thus far in the fourth quarter of 'nineteen. At the conclusion of the review, we'll turn this back over to the operator and open up for any questions that you may have. With that, I'm going to turn it over to Randy Brodrick 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, 11/06/2019. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com. For the three months ended September 3039, the company had oil and gas revenues of $50,300,000 and net income of $9,900,000 as compared to revenues of $32,700,000 and net income of $5,700,000 in the 2018. For the nine months ended September 3039, the company had oil and gas revenues of $143,500,000 and net income of $33,400,000 as compared to revenues of $92,500,000 and net income of $16,100,000 For the three month period of 2019, the net income includes a pretax unrealized gain on hedges of $1,900,000 and a deferred tax benefit adjustment of $674,000 Without these items, net income would have been approximately 7,700,000.0 The three month period of 2018 net income includes a pretax unrealized loss on hedges of $567,000 and a deferred tax benefit adjustment of 724,000 Without these items, net income would have been approximately $5,400,000 For the nine month period of 2019, the net income includes a pretax unrealized gain on hedges of 3,100,000.0 acquisition related costs of approximately $4,100,000 and a deferred tax benefit adjustment of $5,100,000 Without these items, net income would have been approximately $25,800,000 The nine month period of 2018 net income includes a pretax unrealized loss on hedges of $2,500,000 and an additional tax provision of $435,000 Without these items, income would have been approximately $18,500,000 For the three months ended September 3039, our oil price received was $54.59 per barrel, a decrease of 4% from 2018, And our gas price received was $1.14 per Mcf, a decrease of 70% from 2018. On a per BOE basis, the third quarter twenty nineteen price received was $48.93 a decrease of 10% from the 2018 price. Our average price differentials on the oil for the third quarter was under $3 For the nine months ended September 3039, our oil price received was $54.3 per barrel, a decrease of 9% from 2018, and our gas price received was $1.35 per Mcf, a decrease of 60% from 2018. On a per BOE basis, the price received for the nine months ended September 3039, was $49.55 a decrease of 12% from the 2018 price. Production costs per BOE for the three months ended September 3039 increased to $15.04 as compared to $12 in 2018. Production cost per BOE for the nine months ended September 3039 decreased to $12.59 as compared to $13.76 in 2018. For the three month period, the production costs included an accounting adjustment related to the processing fees associated with the bulk of the gas produced on Northwest Shelf assets. These costs were previously accounted for as a reduction of revenues but are now correctly shown as a production cost. This accounting treatment is appropriate because of the marketing arrangement associated with that gas. Additionally, we received older invoices related to the Northwest Shelf assets during the third quarter that had not previously been accounted for. The third quarter production cost per BOE is an anomaly. We believe that our ongoing production cost per BOE, including the processing fee, will be under $12 Most production taxes are based on values of oil and gas sold, so our production tax expense is directly correlated to the commodity prices received. Our production taxes as a percentage of revenues remained relatively flat and should continue to be. Our total depreciation, depletion and amortization, or DD and A, including accretion of asset retirement obligation per BOE for the three months ended September 3039 decreased to $14.63 per BOE as compared to $18.44 per BOE for the same period in 2018. Our total DD and A including accretion per BOE for the nine months ended September 3039 decreased to $14.63 per BOE as compared to $17.73 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 29% for the three month period and approximately 46% for the nine month period ended September 3039 versus the comparable periods in 2018. This is the result of higher production volumes. Our overall general and administrative expense, or G and A, increased $655,000 for the three months ended and $6,200,000 for the nine months ended September 3039, as compared to the same periods in 2018. However, we incurred approximately $4,100,000 in acquisition related costs during the nine month period. Without these additional costs, the increase from 2018 for the nine month period would have been approximately $2,100,000 Excluding the acquisition related costs, on a per BOE basis, this equates to a decrease from $5.33 in 2018 to $3.75 in 2019 for the three month period and a reduction from $5.76 in 2018 to $5.41 in 2019 for the nine month period. Our third quarter twenty nineteen development CapEx was approximately $26,100,000 Along with the approximately $96,900,000 during the first half of the year, this puts the nine month development CapEx at approximately 123,000,000 These amounts exclude acquisition and divestiture related costs and the incursion or assumption of asset retirement obligation. On a diluted basis, the income per share for the three months ended September 3039 was $0.15 as reported. Excluding the six hundred and seventy four thousand dollars deferred tax benefit, the pretax unrealized gain on hedges of 1,900,000.0 and the $793,000 noncash charge for share based compensation, the income would have been $0.12 This is compared to income per share of $09 as reported or $0.10 per share excluding the $567,000 unrealized loss on hedges, the $2,700,000 pretax realized loss on hedges and the $1,000,000 noncash charge for share based compensation in 2018. For the nine months ended September 3039, the income per share was $0.50 as reported. Excluding the $5,100,000 deferred tax benefit, the pretax unrealized gain on hedges of 3,100,000.0 the $4,100,000 acquisition related costs included in G and A and the $2,400,000 noncash charge for share based compensation, the income would have been $0.42 This is compared to income per share of $0.27 as reported or $0.35 per share excluding the $2,500,000 unrealized loss on derivatives, the $6,600,000 realized loss on hedges and the $3,100,000 noncash charge for share based compensation in 2018. As of September 3039, we had $366,500,000 of the $425,000,000 borrowing base drawn on our credit facility and had cash on hand of $7,600,000 Considering cash flows from operating activities, excluding changes in assets and liabilities against development capital expenditures during the period, we were approximately $2,000,000 shy of reaching cash flow neutrality during the third quarter. We continue to firmly believe that at a $50 per BOE received price, we will attain our goal of cash flow neutrality by year end. For the three months ended September 3039, we had adjusted EBITDA of approximately $25,900,000 or $0.43 per diluted share compared to approximately $19,000,000 or $0.31 per diluted share for the same period in 2018. For the nine months ended September 3039, we had adjusted EBITDA of approximately $66,400,000 or $1.31 per diluted share compared to approximately $55,500,000 or $0.92 per diluted share for the same period in 2018. With that, I will turn it back to Tim. All right, Randy. Thank you. I'm going to go ahead and turn it over to Kelly and ask Kelly to review the third quarter operations and updates. Thanks, Tim, and thank you, everyone, for joining us on the call today. In the three months ended September 3039, we drilled six new one mile horizontal San Andres wells on our Northwest Shelf asset. Of the six new wells drilled, three were completed, tested and had initial potentials filed while the remaining three were completed and are in various stages of testing at this time. In addition to the three wells drilled in the third quarter, which had IPs filed, We completed testing and filed IPs on eight additional horizontal wells drilled in the 2019, five in the Central Basin and three on the Northwest Shelf. And the average IP for the horizontal wells, all 11 basically completed and IPs filed in the 2019 was four seventy five barrels of oil equivalent per day or 101 BOE per lateral per 1,000 lateral foot on an average lateral of 4,741 feet per well. We also performed nine conversions from electrical submersible pumps to rod pumps. Four were on the Northwest Shelf, Five were on the Central Basin Platform. And we believe these conversions and you'll hear a little more color on this probably from Danny and Holly and we can certainly cover those in the question and answer period too. But we believe these conversions will lower future operating expense as they will reduce electrical usage, eliminate monthly rental costs in the ESPs and it also lowers our future pulling costs considerably by as much as 80%. All drilling activities and the workovers I just spoke of, all those projects were completed on time and they were all within budget. As a result, net production for the 2019 was approximately 1,015,000 BOEs or 11,033 BOE per day as compared to net production of 600,000 BOEs. And again, that's ring only, that's prior to the Northwest Shelf acquisition. So 600,000 BOEs for the third quarter in twenty eighteen and that's a 69.2% increase. And net production of 976,000 BOE for the 2019 and that's a 4% increase. September 2019 average net production was approximately 11,400 BOEs as compared to net daily production of 7,294 BOEs. Again, that's ring only prior to the Northwest Shelf acquisition. In September 2019 or 2018 rather, a 56.3% increase in net production of 10.8 BOEs in June 2019 and that's a 5.5% increase. As many of you know on the phone today, we started our pilot program in 2016 and we proceeded development with a full development program starting in 2017. And here we are three years later in excess of 150 wells drilled on the horizontal project that we started in 2016. And we're knocking on the door of free cash flow. And we expect to be there very soon. So with that, I'm going to pass it over to Danny and let Danny walk you through some more color on the operations. All right. Thank you, Kelly. Again, appreciate everybody being on the call today. First thing I want to do is address the LOE issue. We'll just get that out on the table. As Randy mentioned, these were we had some extraordinary costs associated with the LOE in this period of time. Previously to this quarter, we had taken the processing fees for the Northwest Shelf as a price reduction on our gas system up there. And the auditors that Randy works with came in and suggested that it would be more appropriate to account for that as LOE. So we had to go back and capture those costs on a in our LOE for, I believe, it's eight months worth of time. So that obviously was a substantial drain on our substantial increase in our LOE for this quarter that would not be there moving forward. In addition to that, we had some invoices that came in over the course of the quarter post closing that had not been previously accounted for, which were associated with our Wishbone acquisition up on the Northwest Shelf. Most everybody knows, it's not uncommon in the transition period like that where you're changing operators where there's a decent confusion with the vendors as far as where they should send their invoices and how they should be processed. And so that is substantially out of the way now. I don't think we're going to see that moving forward. We feel like we've talked to the vendors. Everybody is caught up to date and we don't feel like that's going to be an issue moving forward. Having said that, we still feel very strongly that moving forward, our LOE will be at our historical rate of about $12 per BOE or less. I think personally it will be substantially less than that moving forward. So I think we're going to see some tremendous savings due to some of the things we've got going on, as Kelly mentioned, the rod conversions. The conversions of the smaller or the large ESPs to the smaller ESPs as we move through the life of the well, All those move down our LOE by reducing our electrical costs. The rod conversions substantially lower our LOE moving forward. When we look at future pulling of the wells, as mentioned before, I've talked to many of you before about this, but we're looking at 200,000 to 250,000 to pull and work on these ESPs and rerun them back into the well. Once we move these over to rod conversions that cost drops down to $20,000 to $40,000 per pulling jobs, substantial savings moving forward. So we feel like moving forward as we continue to work through the process of rightsizing our pumps that we're going to see substantial savings. We're already seeing that and I think it will be reflected in future quarters as we move forward once we get this the cloud of these unusual costs out of the way. Just to bring you up to date on where we're at on Q4 as far as our drilling program goes. To date, we have drilled three wells. We've gotten two of those on production. One we got on about two weeks ago and the other we got on around a week ago. The one we put on two weeks ago is already showing around 300 barrels of oil per day and this is climbing, has a substantial high fluid level in it and we're continuing to pump that down at a slow rate. The and we're also doing the same thing on the second well. It's nearing 200 barrels a day after only a week on production, but it is climbing every day as we move forward. We are taking a little slower tack on these wells now as we move into the later stages of the development out there. And that's we visited with several of the other operators in the area who are having substantial success with their new completions and their new processes that they go through as far as completing the wells and then pumping them down. And we've adopted some of those practices. So rather than just get the well immediately and cause problems with sand coming into the well with scale buildup and some other issues that occur with that, we're taking a much slower rate moving those up. And Holly is going to talk about the decline curves and the changes that we've seen. But what you're going to one of the things that we've talked about is we've increased the time to reach peak production on the Northwest Shelf from thirty days to seventy five days. And we feel like that should result in lower costs moving forward as we don't have to deal with, again, sand entry or scale problems moving forward. Those problems have been substantially reduced. Another thing I want to visit with well, let address one other thing on the drilling program. We had originally announced that we would be drilling six wells this quarter. After visiting with some of our non operators, our wells that we have a non operated interest in, we've scaled ours back to five because we have some wells coming in that we have large working interest in. One well we have a 45% interest in. Another we have two more that we own a 20% interest in. Wells that should be substantially as good as ours we feel like. But to avoid going over budget, we decided to scale back the drilling of one of our wells to account for the drilling of those three non operated wells. So what you'll see is us drilling five this quarter instead of six. So that takes into account that. One other thing I want to address is when we talked about our costs moving forward, we updated the decline curves. One of the things we did is we also you'll notice that we cut our costs down substantially. The environment we're in right now, it is the vendors are very hungry. We're seeing a great deal of angst amongst those vendors and they're all fighting for our work. And just to give an example, when we were looking at our frac costs earlier in the year, those fracs on our one mile wells were running anywhere from $900,000 to $1,000,000 a well. We currently and I can say this with absolute confidence, I have seen the invoices on our latest frac jobs that we've done up on the Northwest Shelf. Not only have we gone up on our sand concentration from about 600 pounds per foot to 800 pounds per foot, again, that's after visiting with some of our offset operators and some of the success that they are seeing. But when those invoices now are coming in between 600,000 and $650,000 so you're seeing a substantial savings in these costs. So when we lowered those costs down, we didn't just whittle away at it and say, well, this looks like a good number. No, these are solid, solid numbers and we absolutely believe in that. Any of you analysts out there that anytime you're in town, you want to come by, I will be glad to sit down and share how we came up with these numbers on our AFEs. And but we have absolute confidence in those numbers. So one thing you'll see is we've lowered our costs on the D And C side to 1,900,000.0 on the Central Basin Platform, again, through the savings mostly through our frac costs. What you didn't see is we did not lower our number on the Northwest Shelf. And what we're doing is we're taking advantage of the savings there to increase the size of the frac jobs. And the other thing we're doing in that area in particular is instead of renting pumps now, we are leasing the pump I mean we're buying the pumps, which is a cost of around 150,000 to $200,000 But what that does in the long term is now I'm not paying monthly leasing costs on that plus I own those pumps. Right now when I pull a pump out of the hole, a part of our rental agreement is it has to be repaired back to new. It may only be running at 80% of capacity, but it's still running just fine. But the deal we have is they have to take it in the shop and repair it back to new. By owning these pumps now, I can take that one out. If it still tests out and let's say it's running 80%, I can move that to another well that I own that has less need to move that much fluid. And so that will be a substantial cost savings for us moving forward. So we feel like we're saving money on the leasing side, the repair side and we'll be able to just rerun those pumps without running them through the shop again. So we've got a lot of savings in there. We did see a substantial cost in the drilling side and the completion side, but we've taken advantage of that to increase the frac and start buying the pumps, particularly on the Northwest Shelf. And with that, I'm going to turn it over to Holly and she's going to address the economics and the rest of the decline curve changes. And then obviously, if you all have any questions moving forward, we'd be more than glad to answer those. Thank you, Danny. I'm going to go over the type curve economics, which are available at ringenergy.com, and they are Slide 13 and Slide 16. If I get too ahead of you, you can you can obviously go look at those on the website at any time. We always and continue to review and refine our type curves. When we bought the Northwest Shelf, we put out a very conservative type curve that we thought was easily achievable. As we continue to see our development and how we are completing them and the costs associated with with our actual operations, we've continued to refine it. So I'm gonna start on some of the changes that we're seeing on the Northwest Shelf. On the Northwest Shelf, as Danny alluded to, our drilling costs have stayed the same as our previously stated drilling costs, but they are with an increased frac and buying the pump. We have also included a $200,000 investment at twelve months and that would be a rod conversion from an ESP to a rod lift reducing our long term LOE and OpEx cost going forward as we discussed on the last call. These two things paired with some slight changes in the actual curve parameters as Danny had mentioned the the peak oil rates coming at 75, a slight increase in gas from from a 160 to 300, a decline rate that has decreased somewhat simply because of how we're pumping the weld. And a refinement of the b factor from a 1.5 to 1.45 has had significant impact on our f and d and LOE per BOE, driving it down from an $18.90 per BOE to a $14.19 per BOE. This is a significant reduction, and it translates into a great IRR of an increase from 86% to 131% on net returns on the Northwest Shelf. It has continued to prove as a very accretive acquisition, and we look forward to what we can do with it in the future. While we were doing the type curve revisions, we also looked at the Central Basin platform. You know, we always look at the historical in the area and then also look at the type of inventory we have sitting out there. Based on that, we refined the type curve. The average drilling complete costs dropped by over $300,000 and we included a $250,000 rod conversion that occurred at about twelve months. These two were very impactful once again into the F and D and LOE costs, driving it from a $17.74 to a $15.74 price. This overall increased our internal rate of return from 82% to 99%. We had a slight decrease in initial decline and a final decline going from 6% to 5%. Overall, the type curves are illustrated on our website. And at this point, I'm going to hand it back to Danny. Thank you, Holly. A couple of points I want to make, too, that I wanted to just reaffirm with everybody. The ROC conversion that Holly mentioned is not included in the D and C, but it is included in the economics. So just to be clear, 1,900,000.0 does not include the cost of the ROC conversion. But we show that on that page at a one year mark. And those costs are included in all the IRR and ROI valuations that you see there. The other thing I wanted to point out that I didn't mention before is look, our drill costs are also audited every quarter by our internal external auditors and by our third party engineers. So these are solid numbers. They've been reviewed by outside parties and just want to make that clear to everybody. And with that, I'm going to hand it over to David to talk about market conditions. Thank you, Danny. For the most part, the third quarter was fairly quiet as we focused a good portion of our attention on assimilating the Wishbone acreage and assets into our portfolio. And I'm glad to report that our post closing is complete. And as you've heard from the discussions this morning, we've been quite pleased and are very happy with the performance of these assets to date. One of the ongoing processes is a high grading of our asset base and our leasehold. And as we've mentioned on previous conference calls, we continue to move forward on monetizing some of our noncore assets. Our Delaware Basin property was the first to be marketed with offers due this month, and proceeds from that sale will primarily be used to reduce debt to strengthen our balance sheet. Looking back on the Wishbone assets we purchased in April, we remain extremely pleased with the quality and the quantity of the Tier one and Tier two locations that accompany the acquisition on the Northwest Shelf. We now have over 400 Tier one and two drilling locations, meaning that we forecast these wells when they're drilled to perform in line with our type curves for all three areas that we operate. Even with multiple rigs deployed, you can see we still have an inventory of top tier drilling locations for an extensive number of years to come. With the acquisition of the Yoakum County assets, our appetite for additional acquisitions has taken really a backseat to our focus for debt reduction, cutting costs and becoming cash flow neutral by year end. I'm glad to report that we're on target to accomplish that goal. Since we recognize opportunities can come in a variety of ideas and structures, we're always willing to listen to creative ideas that would have the potential to advance or accelerate our objectives that I've just mentioned. But let me emphasize that we are content with our current inventory of top tier drilling locations that have plenty to keep us busy for many, many years to come. Between now and the end of the year, we also have several non deal roadshows scheduled to include trips to the West Coast, the Midwest and the Northeast. Despite the negative sentiment that continues to overshadow our industry, we believe Ring's story stands as one of the most undervalued conventional oily stories on the street, with our top tier drilling locations resulting in triple digit IRRs and exceptional ROIs that are some of the best in the Permian, even at a $50 realized price. We're going to continue to strive and put forth concerted effort to get our story out. And with that, Tim, I'll turn it back to you for your closing comments. All right. Thank you, David. And thank you, Danny, Holly, and Kelly, Randy. Did a really good job of laying this out. Now this will conclude the portion of of our side. I'm going to turn this back over to the operator, and we're going to open up, operator, for any questions that our listeners may have. Thank you. We'll now be conducting a question and answer session. Our first question today is coming from Neal Dingmann from SunTrust Robinson Humphrey. Your line is now live. Good morning, all thrilled update. My first question is probably for Kelly or Danny. Just given the materially higher estimated PV-ten value, I think now you've got up of over $6,000,000 for the Northwest Shelf that you highlighted on that October 15 update. I'm wondering, will this lead you to have more focus in this play next year versus the platform? Or perhaps you could just speak to how you plan to develop both of these in the next year or so? Neil, this is Danny. No, you're absolutely right. Look, right now, we are working through next year's schedule and budget. Again, as everybody and we continue, we'll pound this with everybody, but with the focus on getting cash flow neutral. Obviously, the biggest bang for our buck right now is on the Northwest Shelf and that's where we do plan to concentrate our drilling next year. If we drill on the CBP next year, it will be commitment wells maybe that we have. But even that, it would be a very minimal number. In fact, everything on the CBP is HBP. So we're working through that right now, but we really strong, strong focus will be on Northwest Shelf. No, that makes sense given the returns there. And then secondly, question for Tim or Kelly. You guys continue to highlight your free cash flow folks, which you certainly, as you mentioned, are closing in on. I'm just wondering, you continue will this continue to be your primary objective in the coming quarters once you've achieved this? And if so, I'm just wondering, Tim, for you or Kelly, how you think about allocating between free cash flow and production, whether production growth, whether we're in a $50 or $60 environment? That's an excellent question, Neil. And it's one that all management teams have pondered and played with for a number of quarters now. There is no question the top of our priority list is to reach cash flow neutral and very quickly into a free cash flow positive position. Growth is important, but right now, it's taking care of the balance sheet. And something that this team is working on diligently and we're going to continue to work on is the improvement of that balance sheet. So turning cash flow positive, being able to retire the debt along the way is something that's important to us. I'm not suggesting that we're going to ignore the opportunity to continue to, from at least a modest standpoint, bring in some growth. We'll have to judge that as we go along depending on the commodity price. But those are two key priorities for us, and we're going to continue down that road. You. Our next question today is coming from John White from ROTH Capital. Your line is now live. Thank you and good morning. Good morning. I wanted to make sure I didn't miss anything on the new completion and production method on the Northwest Shelf. Is that primarily choking the wells back more for the initial month's production? Yes, John. No, that's a good question. And what we've done up there is we have visited look, there's some offset operators up there that are having some, I would say, outstanding success. And they have really refined their methods over the years. We're new to the area. And so we are they are being very gracious in sharing information with us and so and we greatly appreciate that. We also have interest in their wells. They have interest in our wells and so it makes sense for us to share this information. But John, what we've done, typically down on the Central Basin Platform, we have done about a 400 pound per foot frac job, modest. But it was appropriate for that particular area. The oil column is a little thinner down there. And really all we're trying to do down there is connect little porosity pods. So it's a little different. Up on the Northwest Shelf, the rock is much more uniform. It's much thicker. It still has good porosity, but we don't see those pods of porosity clear like we do on the Central Basin Platform. It's much more consistent rock. And visiting with our offset operators, they have over the years continued to ramp up their fracs and they're seeing some really, really nice success. One of the other things they're doing well and let me say, so they've ramped up to about 800 pounds per foot and that is the model that we're currently using right now too. And we're just now getting our first wells online with that particular frac. And so hopefully by the end of the quarter, we'll have information to share on that with everybody as to what we're seeing. But the other thing is that obviously everybody is familiar up in that area with the scale issue that some of the early operations ran into where they were pulling the wells hard. They weren't using sufficient scale inhibitor in the frac job itself and it was causing a lot of problems with very expensive drill outs where they had to go in with a drill bit basically and drill all that out and then run a converter and then acidize it. And it was quite a process. They seem to have eliminated a lot of that issue as well as sand entry coming back into the wellbores by limiting the drawdown per day on those wells. I'm not going go into exactly what that number is, but they've shared it with us and we're following that same model. And so we hope to see that same success. I know they've had some wells that they've been have substantial run times on well over a year without having to pull the well, which is fantastic. And it's also causing the declines to be flatter on the backside as opposed to going up very sharply and coming down very sharply. So really it just kind of evens everything out, eliminates problems with scale, eliminates problems with sand. And then that also goes back to the pumps that we're running in that particular area. There's only one company that builds a particular pump that the offset operators are using. They're having tremendous success, tremendous run times with them. But the company that does that will only sell them. They won't even rent them. So that's the reason we've gone to the purchase of those in addition to the fact now too that I don't have to repair them back to new every time if they're still in good shape. I can put them in a well, say, I originally started out with a well that was making 3,000 barrels, 3,500 barrels of fluid a day. Once another well drops down to 2,000, well, I can certainly take a well a pump that's still running at 80% efficiency, take it out of the bigger well and move it over to the smaller ones. Anyway, it makes a lot of sense to us. Again, they've been at this now up in that area for about six, seven years. We've been at it for six months. And we've been very, very happy with the amount of sharing that is going on up in there and we're going to take full advantage of it. I really appreciate the detail on that. Thanks very much. With a follow-up, on the Delaware Basin divestiture, would you in percentage terms of total value, would you expect people to allocate how would you expect people to allocate value to the water system versus the reserves and production? John, that's a good question. Go ahead, Tim. Go ahead. Okay. So over the last three years, we've had a number of people come into our shop that have run at us on the water system. And I would say that the oil reserves are obviously going to be worth more than the water. But the water system has a value, a meaningful value. We own a lot of surface out there. We own a lot of North South pipeline associated connecting those systems, creating redundancies up and down about a 15 plus mile stretch. As a result of that, if you were a third party entity, you could take advantage of that. And we've had people run at us. It just hasn't been a model, John, that really is one that we could jump on just yet. And so we weren't really excited about necessarily pairing that off separately. And then of course, you'd have to lease back your ability to dispose of water on top of that, which does affect your overall model that your financial model on the oil side. So I would say that the water is worth a little bit less. I can't really speculate what that would be. It's sort of a duty in the eyes of the beholder. But the oil is going to be worth more. And if you combine those two pieces with each other, I think as a combined asset, it has a little higher value there again. Sounds reasonable. And again, appreciate the details. This will keep David busy during the holidays. Thank you, Todd. Thank you. Our next question today is coming from Noel Parks from Coker and Palmer. Your line is now live. Good morning. Good morning, Noel. I just had a couple of things. I remember you've talked in the past a little bit about just the the spilling the spacing that's been drilling up on the Northwest Shelf and a a little bit about the the parent channel well interactions. And I wonder if you just have any any updated information on that. Danny, you Yes. Got some Tim, thanks. No, no. Yes, that's a great question. We have talked about this in the past, and I believe at some point you will definitely see us add some slides into our presentation, our corporate presentation where we illustrate some of this. But again, the Northwest Shelf does not have the parent child issues that you see with the Wolfcamp and the Spraberry plays or the Bone Spring plays with the unconventional drillers. And particularly on the Northwest Shelf, it's a very unique geology up there. And what we're actually seeing is that the parent wells are used to draw the pressures down in the area and then the child wells come in later and take advantage of that. And what I mean by that is the rock up on the Northwest Shelf, and it's going get a little deep, but the rock up on the Northwest Shelf is what we call oil wet, which is kind of an unusual situation. In most cases, find water like down on the Central Basin Platform, it's called a water wet reservoir. And what that simply means is you have the grains of the rock in the formation and attached to that are these on a water wet is water. And in the area in between, you have the oil sitting free. Up on the Northwest Shelf, it's the opposite. We have the oil is actually clinging to the rock and the water is sitting in the open spaces. And what you have to do in that particular case is you have to pull the pressures down to the point where the gas that's trapped inside of the oil will expand. And when that happens, it pushes the oil off the rock. And I liken it to when you shake up a Coke bottle and then you pop the lid on it and all of a sudden it just starts foaming. What you did is you took the pressure off and allowed the gas to come out of formation or out of solution and now you've got the drive and it pushes the coke out of the bottle. The exact same thing we see on the Northwest Shelf. So as the parent well comes in, its job is to come in and draw the pressures down in the area. And once it reaches a certain point, we start seeing that inflow of oil come in. Some areas that can especially in the early stages of the development up in that area, some of these guys were pumping water for six months to a year before the oil was coming in. And we were looking at them thinking they were crazy. And it turns out they weren't so crazy. So what we're looking at now is as the child well comes in, it takes advantage of the fact that the pressures are drawn down. So it sees oil quicker. And what we're seeing is that on a say on a cumulative per day ratio or cut curve, as you see that the child wells are vastly outperforming the parent wells by taking advantage of the initial pressure drawdown. So we don't have that issue that they see in the other areas, especially in a water reservoir. If you overdrill it, you will see the child wells will not perform as well. We have the opposite up on the Northwest Shelf. Appreciate you asking that question. You bet. And so as far as just the drilling density you'll ultimately head toward, it sounds like you have some motivation to try to on the side of going tighter. Is that fair? There's no doubt about it. Look, we have there's operators in the area that have already downspaced to seven and eight wells per section and are still seeing very high success rate. Wishbone in their early stages commissioned a report from Vangaten Engineering, is a very well respected engineering firm out of Houston. And in their write up, they said there's no doubt you can go to eight wells per section without seeing interference. We have not done anything quite that concentrated yet. But some of the other operators up in the area have and they're still seeing very nice success. Yeah. And for your inventory, what's the density you're assuming? We most of ours are well, I mean, we originally started out thinking we would probably do six like we've done on the Central Basin Platform. But we're certainly open to drilling the seventh and eighth wells. And so that's something we've kind of got in our pocket if we need it later. The current economics reflect six, though? Yes. Current economics, reflect six. Great. And just one last thing. I just didn't quite catch a couple of numbers you were talking about. You were saying that for the the rod pumps, the pulling job ran 20 to $40,000, and that's as opposed to the the ESP cost. What what was the the higher cost for those? Right. Now pulling pulling in pulling the ESP wells is running runs about 200,000 per well. Okay. So, like, 80% cheaper really. It's an 80% reduction in future pulling costs. Thank you. Our next question today is coming from John Thomas, a Private Investor. Your line is now live. Thank you. Well, on a fine third quarter. As a matter of fact, a great nine months and expanding it a great couple of years. Unfortunately, all the work that you folks have been doing hasn't showed in the value of the stock. Currently, you're doing about 1,100 barrels a day and at $50 a barrel, that translates into about $200,000,000 annually. And it's great to hear the projections for cross reductions, increased IPs, and so on and so forth. I think in order to get out of the box that you've been in for the past twelve, fifteen months with with stock price evaluation, you have to start thinking out of the box. And my proposal is a simple one. With a $200,000,000 projected income at current levels and at $50 per barrel, not at 54 or the current price of 57, I would like to see the company start paying a dividend. And it could be a modest dividend. It could be a million dollars paid out over the year, which would equate to about 15¢ per share. This would expand your coverage other than the research people that are covering it now. I believe that would help shareholder value. I've been a long term investor. I was there day one with Ring, and I've been there day one, also with Arena. I have an investment that I made when the stock first came out. And all this all this great work has not shown any any profit or potential for the investor. So I would like, first of all, for you folks to consider paying a dividend. I'll give you some thought on that. And my second question is that you had a private investor that recently purchased 8,000,000 shares. I would like to have some your thoughts and comment on that. Thank you. Well, you, John, and good questions. This is Tim. So let's approach the first question first, the subject of dividends. Look, you have been a long term shareholder, as you explained, going back from the Arena days now over to the current company of Ring, and we appreciate that. You've been a great supporter, obviously. But I know that you want us to do the very best job that we can, not only with what we've reported here on this morning for the first nine months of this year and years prior to that, but also going forward, you know that what's important to us is to take care of our balance sheet, and that is critical to us. So along the way, you're going to see us continue to put a strong effort forward to reduce that balance sheet, whether it's through free cash flow that's going to start developing before too long or whether it's through monetizing an asset that's not one of our core assets. And that's to be tough for us. As relates the surplus of cash and we're able to do that and do we consider something else with that cash, one would say, well, what about a stock buyback? Or what about something else to consider, maybe a dividend? Or what about possibly even stepping up with the returns that we're seeing on the wells, that we're delivering here on the Northwest Shelf? We have to consider stepping up that activity because you have to admit, internal rate of return to 130% is pretty doggone nice. So I will share this with you. We're not close minded as it relates to considering dividends and doing something for our shareholders. That's something that we will consider and that we will discuss. You have my word on that. But I want to reinforce that our main objective is to work on that balance sheet and continue to do what we've been doing operationally. The second part of your question related to not 8,000,000 shares, but about 5,500,000.0 shares that have been purchased that represented a little over 8% ownership of the company. We applaud those folks. They recognize an opportunity, and they recognize a stock that's grossly undervalued. And, we know those folks. We talk to them from time to time, and we continue to have conversations with them. They have some great ideas for us to consider. And, so, nothing formal is going on there, but we we are in in general conversations, and, we welcome their position and their investments just like we do the rest of shareholders. Well, thank you. I mentioned the dividend because it was a modest amount. It was 1,000,000 of your total projected revenue for a year. I think you could accomplish both, improve your balance sheet and provide value to the stockholders simultaneously. So I would sincerely hope you would give that a high level of consideration. We'll do that, John. All right. Thank you, Tim. Thank you. Thank you. Our next question today is coming from Andrew Bond from Alliance Global Partners. Your line is now live. Good morning, all. Good morning. It looks like you're seeing some good results with the workover rod pump conversion program. As you look towards fourth quarter and 2020, with debt reduction cost cutting and cash flow neutrality in mind, how are you thinking about balancing your capital spend between that and your D and C development, especially considering these new type curves and the favorable results you're getting on the Northwest Shelf? So Andrew, I'm going to turn this back to Randy. But just to begin with, we have yet to put out a formal CapEx for next year. But as Danny noted earlier on the call, we're working on that now. But why don't you go ahead and shed a little light on that, Danny? Sure. No, the look, those ongoing side by side processes. Obviously, what we do is we look at our how many wells we want to drill per quarter per year. And then we work the rest of the budget around that. But we are doing a substantial number. So far this quarter, we've done seven rod conversions. So it is an active program for us because we see the benefits down the road. One thing and this is a little bit of just interpolation that I'm seeing, and Holly will help me as we get farther down the road. We just started these rod conversions earlier this year. But it appears that we're seeing a flattening of our decline up on in the Central Basin Platform in particular as we move forward with the conversions. So that's exciting to me moving forward. So it makes sense to kind of run both of those in parallel. We don't but we do set a limit on the number of rod conversions we're going do because the primary focus is still drilling. But I'd say drilling is one and rod conversions and the workovers are 1B. So but always the focus is starting with the drilling and then we see how much we can spend on the rest of it moving forward. That makes sense to have them kind of side by side and separate. Very good to hear that you're seeing that flattening of the decline on the Central Basin Platform. Thanks very much for your time and good job on the quarter. Thank you. Thanks. Thank you. Our next question is coming from David Russell from Ring Energy. Your line is now live. Good morning, everyone. I have a quick question about the hedging program. I've noticed that you're letting your current hedges sort of run off for 2019 and you haven't added anything for 2020. Do you have any thoughts about that? Yes. As a matter of fact, David, you're right. They the 19s will be running off, but but we actually have paid a lot of attention to that. We've just recently added for '20, and we continue to work on that. Thank you. We've reached the end of our question and answer session. I'd to turn the floor back over to management for any further or closing comments. All right. Thank you, operator. Well, listen, everyone, we know there are a number of calls today, and we're all busy folks. We appreciate your time. As always, we want you to know that our phone lines and doors are open. We welcome your comments and your thoughts and ideas. And of course, Bill Parsons, who talked to a number of you, is available as well. So with that, thank you very much. Thank you. That does conclude today's teleconference. You may disconnect your line at this time, and have a wonderful day. We thank you for your participation today.