Ring Energy, Inc. (REI) Q3 2019 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy 2019 Third Quarter and Nine Month Financial and Operating Highlights Conference Call. [Operator Instructions] 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 2019 third Quarter and nine month Financial and Operations Conference Call for Ring Energy. Again my name is Tim Roger, 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 Broaddrick; Executive VP In-Charge of Operations, Danny Wilson; Hollie 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 30, 2019. We will also review our results and provide some insight as to the current progress thus far in the fourth quarter of 2019 at the conclusion of the review will 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 Broaddrick, and asked 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, November 6, 2019. If you do not have a copy of the release this one will be posted on the company website at www.ringenergy.com. For, the three months ended September 30, 2019. The company had oil and gas revenues of $15.3 million and net income of $9.9 million as compared to revenues of $32.7 million and net income of $5.7 million and the third quarter of 2018. For the nine months ended September 30, 2019. The company had oil and gas revenues of $143.5 million and net income of $33.4 million as compared to revenues of $92.5 million and net income of $16.1 million. For the three month period of 2019, the net income includes a pretax unrealized gain on hedges of $1.9 million and a deferred tax benefit adjustment of $674,000, without these items, net income would have been approximately $7.7 million. 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 $5.4 million, for the nine month period of 2019, and that income includes a pretax unrealized gain on hedges of $3.1 million acquisition related costs of approximately $4.1 million and a deferred tax benefit adjustment of $5.1 million. Without these items, net income would have been approximately $25.8 million. The nine month period of 2018 net income includes a pretax unrealized loss on hinges of $2.5 million and an additional tax provision of 435,000, without these items, net income would have been approximately $18.5 million, for the three months ended September 30, 2019, 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 VOB basis, the third quarter 2019 price received it was $48.93, a decrease of 10% from the 2018 price. Our average price differential on the oil to the third quarter was under $3. For the nine months ended September 30, 2019, our oil price received was $54.03 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 VOD basis, the price received for the nine months ended September 30, 2019, was $49.55, a decrease of 12% from the 2018 Press. Production costs per BOE for the three months ended September 30, 2019, increased to $15.4, as compared to $12 in 2018. Production cost per BOE for the nine months ended September 30, 2019, decreased to $12.59, as compared to $13.76 in 2018. For the three month period, the production costs including an accounting adjustment related to the processing fees associated with the bulk of the gas produced on our 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 Voices related to the northwest West shelf assets during the third quarter that had not previously been accounted for. The third quarter production costs 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 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 she continued to be. Our total depreciation, depletion and amortization or DDNA, including a creation of Asset Retirement obligation per BOE for the three months ended September 30, 2019, decreased to $14.63 per BOE as compared to $18.44 per BOE for the same period in 2018. Our total DDNA including the creation for BOE for the nine months and it's September 30, 2019, 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 DNA increase to approximate by approximately 29% for the three month period, and approximately 46% for the nine month period ended September 30, 2019 Versus the comparable periods in 2018. This is the result of higher production volumes, our overall general and administrative expense or G&A increased $655,000 for the three months ended, and $6.2 million for the nine months and it's September 30, 2019 as compared to the same periods in 2018, however, we incurred approximately $4.1 million 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 $2.1 million, excluding the acquisition related costs on a per basis. This equates to a decrease from $5.33 in 2018 to $3.75 in 2019 for the three month periods, and a reduction from $5.76 in 2018 to $5.41 in 2019 for the nine month period. Our third quarter 2019 development CapEx was approximately $26.1 million, along with the approximate $96.9 million during the first half of the year. This puts the nine month development CapEx at approximately $123 million. These amounts of 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 30, 2019 was $0.15 as reported, excluding the $674,000 deferred tax benefit. The pretax unrealized gain on hedges of $1.9 million and the $793,000 non-cash charged for share based compensation, the income would have been pulled since. This is compared to income per share of $0.09 as reported, or $0.10 per share, excluding the $567,000 unrealized loss on hedges the $2.7 million pretax realized loss on hedges and the $1 million non-cash charged for sheer based compensation in 2018. For the nine months ended September 30 2019, the income per share was $0.50 as reported, excluding the $5.1 million deferred tax benefit that pretax unrealized gain on hedges of $3.1 million. The $4.1 million acquisition related costs included in G&A and the $2.4 million noncash charged 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 $2.5 million unrealized loss on derivatives. The $6.6 million realized loss on hedges and the $3.1 million non-cash charged for share based compensation 2018. As of September 30, 2019, we had $366.5 million of the $425 million born based drawn on our credit facility and had cash-on-hand of $7.6 million. Considering cash flows from operating activities excluding changes in assets and liabilities against development capital expenditures during the period, we were approximately $2 million share of reaching cash flow neutrality during the third quarter. We continue to firmly believe that at a $50 per bill we received price, we will attain our goal of cash flow neutrality by year-end. The three months ended September 30, 2019, we had adjusted EBITDA of approximately $25.9 million, or $0.43 per diluted share, compared to approximately $19 million or $0.31 per diluted share for the same period in 2018. For the nine months ended September 30 2019, we had adjusted EBITDA of approximately $66.4 million, or $1.31 per diluted share, compared to approximately $55.5 million 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 into September 30, 2019, we drilled six new one-mile horizontal San Andres wells on our North West Shelf asset. 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 first in the second quarters of 2019, five in the Central Basin and three on the North West Shelf. And the average IP for the horizontal wells, 11 basically completed and IPs filed in the third quarter of 2019 was 475 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 perform nine conversions from electrical submersible pumps, to rod pumps four on the northwest shelf, Fiver on the central patient platform, and we believe these conversions and you'll hear a little more color on this probably from Danny and Hollie. And we can certainly cover those in the question and answer period too, but we believe these conversions lower future operating expense as they will reduce electrical usage, eliminate monthly rental costs in the ESP and it also lowers our future pulling costs considerably by as much as 80%. All drilling activities and the workers I just spoke of all those projects were completed on time and they were all within budget. As a result of net production for the third quarter of 2019 was approximately 1,015,000 BOE or 11,033 BOE per day, as compared to net production of 600,000 BOE and that's ring only that's prior to the Northwest shelf acquisitions with 600,000 BOE for the third quarter in 2018 and that's a 69.2% increase and net production of 976,000 BOE for the second quarter of 2019 and that's a 4% increase. September 2019 average net production was approximate 11,400 BOE as compared to net daily production of 7294 BOE again, that's ring only private Northwest shelf acquisitions. In September 2019 or 2018 rather, a 56.3% increase in net production of 108 BOE in June 2019 and that's a 5.5% increase. As many of you know on the phone today and we started our pilot program in 2016 and we proceeded with the full develop program starting in 2017. Here we are three years later in excess of 150 wells drilled in the horizontal project that was started in 2016 and were 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 a walk you through some more color on the operations.

Thank you, Kelly and again appreciated by being on the call today. First thing I want to do is address the LOE issues that out in the table. As Randy mentioned 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 price reduction on our gas system up there and the auditors the Randy works with came in and suggested that it be more appropriate account for that as LOE. So we had to go back and capture those costs in our LOE, I believe its eight months' worth the time. So that obviously was a substantial in our LOE for this quarter that would not be there moving forward. In addition to that we had 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 upon the Northwest shelf, most everybody knows it's not uncommon in the transition like that where you are changing operators for there to be some confusion with the vendors as far as where they should send their invoices in and how they should be processed. And so that is substantially out of the way. Now don't think we're going to see that moving forward, we feel like we talk 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 are 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 small or the large to the smaller ASPs, as we move through the life of the well. All those move down our LOE by reducing our electrical cost. 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 you know we're looking at $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 Trump's drops down to $20,000 to $40,000 for pulling jobs a substantial savings moving forward. So we feel like moving forward as we continue to work through the process of right-sizing our pumps that we're going to see substantial savings. We've already seen that and I think it will be reflected in future quarters as we move forward, once we get this the cloud of this - 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've 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 is climbing has a substantial higher fluid level in it and we're continuing to cut that down at a slower rate. 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 moving into the later stages of the development out there and you - we visited with several of the other operators in the area and who are having substantial success with their new completions and their new process is 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 build up and some other issues that occur with that we're taking a much lower rate moving those up and that Hollie is going to talk about the decline curves and the changes that we've seen, but what you're going to be one of the things that we've talked about is we increased the time to reach peak production on the northwest shell from 30 days to 75 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. Now the thing I want to visit with - Well, let me 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 and we've scaled ours back to five because we have some wells coming in, we have a large working interest in one well, we have a 45% interest in another we have two more than we own a 20% interest in. Wells it 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 wills to account for the drilling of those three non-operated Well, 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, you know, when we talked about the cost 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. You know, the environment we're in right now. It is the vendors are very hungry. We're seeing a great deal of amongst those vendors, and they're all fighting for our work. And just to give an example, when we were looking at our drilling our frack costs earlier in the year, those fracks on our one mile wells, we're running anywhere from $900,000 to $1 million of well, we currently and I can say this with absolute confidence. I have seen the invoices on our latest frack jobs that we've done up on the northwest shelf, we're not only have we gone up on our sand concentration from about 600 pounds per foot to 800 pounds per foot, again at that's after visiting with some of our offset operators in the some of the success 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 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 won't come by, I will be glad to sit down and share how we came up with these numbers on RA fees. And we have absolute confidence in those numbers - so one thing you'll see is we've lowered our costs on the DNC side to $1.9 million on the central basin platform, again, through the savings mostly through the rough frac cost. What you didn't as 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 fracked jobs. And the other thing were doing in that area in particular is instead of renting pumps we're buying the pumps which is a cost of around the $150,000 to $200,000. But what that does in the long-term is now not paying monthly leasing costs on that, plus I own those pumps. Right now when I pull up about the whole a part of our rental agreement is it has to be repaired back to new. It may only be running it 80% of capacity but it's still running just fine, but the deal we have is they have taken the shop and repair it back to new by owning these comps now. I can take that one out if this still tests out and it says its 80%. I can move that to another well that I moved, there has less need to move that much fluid. And so that'll 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 will be able to just rerun those pumps without running through the shopping again. We got a lot of savings in there; we did see a substantial cost of the drilling side and the completion set that we've taken advantage of that to increase the fracked and start buying the pumps particularly on the North West shelf. And with that, I'm going to turn it over to Hollie and she is going to address the economics and the rest of the decline curve changes and then obviously if you all have any questions moving forward 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 on Slide 13 and Slide 16 if I get too ahead of 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 North West Shelf, we put out a very conservative type curve that we felt was easily achievable. As we continue to see our development and how we are completing them in the costs associated with our actual operations. We've continued to refine it. So I'm going to start on some of the changes that we're seeing on the North West Shelf. On the North West 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 pumps. We have also included a $200,000 investment at 12 month and that would be a REIT conversion from an ASP to A-Rod, reducing our long-term LOE in OpEx costs going forward as we discussed on the last call. These two things paired with some slight changes in the actual curve framework as Danny has mentioned the peak oil rates coming at 75, a slight increase in gas from 160 to 300 and a decline rates that has decreased somewhat simply because of how we're pumping the wells and a refinement of the B factor from the 1.5 to 1.45 has had significant impact on our F&D in 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 increased from 86% to 131% on net returns on the North West Shelf. It is continuing 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 central based n platform, we always look at the historical area and then also look at the type of inventory we have sitting out there. The average drilling complete cost dropped by over $300,000 and we included a $250,000 rod conversion that occurs at about 12 months. These two were very impactful once again into the F&D in LOE cost diving it from a $17.74 to $15.74 price. This overall increase 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, Hollie. Couple of points I want to make to that wanted to just reaffirm with everybody. The [indiscernible] that Hollie mentioned is not included in the DNC. But it is included in the economics. So just to be clear, the 1.9 does not include the cost of the route 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 mentioned before is look our drill cost are also audited every quarter by our internal, external auditors and by our third party engineer, so these are solid numbers that have been reviewed by outside parties and just want to make that clear to everybody. And with that, I am going to hand it over to David to talk about market conditions.

Thank you, Danny. For the most parts, the third quarter was fairly quite as we focused a good portion of our attention on a simulating the Wishbone acreage in assets into our portfolio. And I am glad to report that our post-closing is complete and as you've heard from discussions this morning, we've 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 lease hold. And as we've mentioned on previous conference calls, we continue to move forward on monetizing some of our non-core assets. Our Delaware Basin property was the first to be marketed with office do 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 of this year, we remain extremely pleased with the quality and the quantity of the Tier 1 and Tier 2 locations that accompany the acquisition on the Northwest shelf. We now have over 400 Tier 1 and 2 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 - only a back seat or focus for debt reduction, cutting cost and becoming cash flow neutral by year end. I am glad to report that we are on target to accomplish that goal. Since we recognize opportunities can come in a variety of ideas and structures, we are always willing to listen to creative ideas that would have the potential to advance or accelerate or objectives that I've just mentioned. But let me to emphasis that we are content with our current inventory of top tier drilling locations that have plenty to keep us busy for many years to come. Between now and end of the year, we also have several non-deal road shows scheduled to include trips for West Coast to Midwest and the north east. Despite the negative settlement that continues to over shadow our industry, we believe bring story stands as one of the most undervalued conventional OLE 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 are going to continue to strive and put forward the consolidated efforts 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 and Randy really good job of laying this out. Now this will conclude the portion from our side. I'm going to turn this back over to the operator. And we're going to open it up for any questions that our listeners may have.

[Operator Instructions] Our first question today is coming from Neal Dingmann from SunTrust Robinson Humphrey. Your line is now live.

My first question probably for Kelly or Danny. Just given materially higher estimated PV10 value, I think now you've got up of over $6 million for the North West Shelf that you highlight on that October 15th 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?

So, Neal 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 North West 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, it will be commitment wells may be that we have. But even at 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 North West 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, will you continue or 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 that'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, very quickly into 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 to cash flow positive, been 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 a, at least a modest standpoint. I'll bring us 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.

Perfect, thanks. I look for Delta growth.

Our next question today is coming from John White from ROTH Capital. Your line is now live.

Thank you and good morning. I wanted to make sure I didn't listen anything on the new completion and production method on the North West Shelf. Is that primarily choking the wells back more for the initial months production?

Yes, John. Now, that's a good question. What've done up there we've visited, there is some offset operators up there they are having, I would say outstanding success and they have really refined methods over the years. We're new to the area and they are been gracious and sharing information with this and we greatly appreciate that. We also have interest in their wells, they have interest in our wells and it makes sense for us to share this information. The job what've done typically down on the central basin platform. We have done about £400 per foot frac job modest but it was appropriate for that particular area. The well columns are little thin or down there and really all we're trying to do down there is connect pod, so it's a little different. On the North West shelf the rock is much more uniform, it's much thinker. Still has good porosity but we don't see those pods 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 year continue to ramp up there fracs and they are seeing some really, really nice success. One of the other things they are doing and let me say they ramped up about £800 per foot and that is the model that we're currently using right now to. And we're just now getting our first wells online with that particular frac and hopefully by the end of the quarter we will have some information to share on that with everybody to what we're seeing. But the other thing is that obviously base premier up in that area with the scale issue that some of the early operations are in into where they were pulling the wells or they weren't using sufficient scale inhibitor in the frac job itself and it was causing a lot of problem, very expensive drill out so where they have to go in but the drill basically and drill all that out and then run a convertor and then ask to dive in, it was quite a process. They seem to eliminate it a lot of that issues as well as sand entry coming back into the well board by eliminating the draw down per day on those wells. I'm not going to exactly what that number but they have shared with us and we're following that same model. And so we hope to see the same success. I know they have some wells that they been have substantial run time on well over 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 it's just kind of even everything is out, eliminate problem with scale, eliminate problem with sand. And then that also goes back to the pumps that we're running in that particular area. There is only one company that builds the particular that the offset operators are using. They are having tremendous success, tremendous runtimes with them but the company that does will only sell them, they won't even rent them. So that's the reason we gone to purchase of those in addition to the fact now to that I don't have to repair them back to new every time if they are still in good shape. I can put them in a well say, reasonably start out with a well that is making 300 barrels to 3500 barrels a fluid a day, another well drops down to 2000 and certainly take the pump that still run at 80% efficiency take it out the bigger well and move it over to the smaller one. It just makes a lot of sense to us. They again look, they've been at this now up in that area for about 6, 7 years, we've been at it for 6 months and we've been very, very happy with Mount 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, 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. Okay. So you know over the last three years, we've number of people come into our shop that have run has 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 you if you were a third-party entity, you could take advantage of that and we've had people run out of it so it just hasn't been a model, John, that really is one that we could jump on just yet. And so we weren't real excited about necessarily paying that off separately and then of course, you'd have to lease back your ability to dispose of water on top of that which has affect your overall model that your financial model on the oil side. So I would say the water's work a little bit less like I can't really speculate what that would be sort of a duty in the eyes of the beholder the goal is going to be worth more. And if you combine those two pieces of each other. I think as a combined asset, it has a little higher value there again.

Sounds reasonable and again appreciate the detail and this will keep David busy during the holiday.

Our next question today is coming from Noel Parks from Coker & Palmer. Your line is now live.

Just had a couple of things. I know we've talked in the past, a little bit about just the spacing you've been going up on in the North West Shelf and a little bit about the parent channel but well interactions. And I wonder if you just have any updated information on that.

No - yeah, that's a great question. We have talked about this in the past and I believe at some point, we will definitely see us add some slides into our presentation. Our corporate presentation where we illustrate some of this, but again the North West Shelf does not have the parent child issues that you see with the Wolfcamp in the Spraberry plays or the Bone Spring play that with the unconventional drillers and in particularly on the North West Shelf. It's a very unique geology out there and what we're actually seeing is the parent wells are used to draw the pressure is 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 North West Shelf and this can get a little a little deep, but the north up the oil or the rock up on the North West Shelf is what we call oil where, which is kind of an unusual situation in most cases you found water particularly like down on the Central Basin Platform it's of called water wet reservoir and what that simply means is, you have the grains of the rock in the formation and attached to that or these - are on a water is water and in the area in between, you have the oil sitting free up on the North West Shelf is the ops, we have the oil is actually cleaning 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 in - 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 in new popped a lid on it and all of a sudden just start following that 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, exact same thing we see on the North West 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 like and especially in the early stages of the development up in that area, some of these guys were pump in water for 6 months to a year before the oil is coming in and we were looking at. I'm thinking they were crazy and it turns out, they were so crazy. But what - so what we're looking at now is the child well comes in and it takes advantage of the fact that the pressures are drawn down so it sees oil quicker and what we're seeing is it on a - say on a cumulative per day ratio our type curve, as you see 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 over drill it and you will see that the child wells will not perform as well, we have the opposite upon the North West Shelf. I appreciate you asking that question.

And so, as far as just the density is going back to your ultimately head toward it sounds like you got some motivation to try to air on the side of flooring tighter, is that fair?

There is no doubt about it. Look we have - there's operators in the area that have already down spaced to 7 and 8 wells per section and are still seeing very high success rate. Wish Bone in their early stages commissioned a report from Vanguard, engineering, which is a very well respected engineering firm out of out of Houston and they in there, right. They said there is no doubt you can go to 8 wells per section without seeing interference. We've not done anything quite that concentrated yet but some of the other operators area have and they are still seeing very nice success.

In your inventory what's the density you're assuming?

We originally started out thinking we would probably do 6, like we did on the central basin platform. But we're certainly open to drilling the 7 and 8 wells and that's something we got in our pocket if we need it later.

The current economics reflects its style.

And just one last thing, I just didn't quite catch a couple of number you're talking about. You were saying for the rod pumps, job rent $20,000 to $40,000 and that's how suppose to the ESP cost, what was the higher cost for those?

Pulling ESP wells runs about 200,000 per well.

Okay. So, like maybe like in percent cheap, really...

It's an 85% debt. Right. It's an 80% reduction in future pulling costs.

Our next question today is coming from John Thomas, a Private Investor. Your line is now live.

Well, congratulations on a fine third quarter, is a matter of fact a great nine months and expanding a great couple of years. Unfortunately, all the work that you folks have been doing hasn't showed in the value of the stack. Currently, you're doing about 1100 barrels a day and that $50 now is a barrel that translates into about $200 million 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 12 to 15 months with what's stock price the valuation, you have to start thinking out of the box and my proposal is simple one. With a $200 million projected income at current levels and at $50 per barrel. Not at 54, 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 $1 million paid out over the year, which would equate to about $0.15 per share. This would expand the 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 wish there day one with ring, and I've been there. Day one, also with arena, I have an investment and I made when the stack first came out, in all this all this great work has that shown 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 than that. And my second question is that you had a private investor that recently purchased 8 million shares. I would like to have some kind of your thoughts and comment on that? Thank you.

Well, thank 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 and now over to the current company of ring. And we appreciate that you've been a great support. 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 9 months of this year and years prior to that, but also going forward, 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 going to be tough for us as it relates to the surplus of cash and we're able to do that and do we consider something else with that cash. I would say, well, what about the 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 North West Shelf. We have to consider stepping up that activity because you have to admit internal rate of return of 30% pretty that gone 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 that 8 million shares, but about 5.8 million shares that have been purchased that represented a little over 8% ownership of the company. We applaud those folks. They recognize an opportunity; they recognize a stock that's grossly undervalued. And we know those folks, we've talked to him 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 are 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 million of your total projected revenue for a year. I think you could accomplish both, improve your balance sheet and provide value to stockholders simultaneously. So I would sincerely hope you would give that a high level of consideration.

We will do that job.

Our next question today's coming from Andrew Bond from Alliance Global Partners. Your line is now live.

Looks like you're seeing some good results with the work over rod pump conversion program. As you look towards fourth quarter in 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 DNC 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 cape for next year but as Danny noted earlier on the call. We're working on that now, but once we haven't shut a little light on that, Danny.

Sure. Now the look, those are ongoing side by side processes. Obviously, what we do is we look at our how many wells we want to drill purport for a 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 road conversions. So it is an active program for us because we see the benefits down the road. And one thing that you know, and this is a little bit of just interpolation that I'm seeing in Hollywood helped me as we get farther down the road, you know, we just started these road conversions earlier this year. But it appears that we're seeing a flattening of our decline up on - in the central base and 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 NIM Rod conversions. We're going to do because the primary focus is still drilling. But I'd say drilling to one and Rod conversions in the walkovers 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 it then 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.

Our next question is coming from David Russell from [Ring Energy]. Your line is now live.

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 19s will be running off, but, but we actually have painted paid a lot of attention to that we've just recently added for 20 and we continue to work on that.

Thank you. We reached end of our question-and-answer session. I'd like to turn the floor back over to management for any further or closing comments.

All right, thank you operator. We'll 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 talks 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 lines at this time and have a wonderful day. We thank you for your participation today.