Greetings, welcome to the Ring Energy 2019 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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. 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 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 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 30th, 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, we'll turn this back over to the operator and open up for any questions that you may have.
I'm going to turn it over to Randy Broaddrick 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, November 6th, 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 30th, 2019, the company had oil and gas revenues of $50.3 million and net income of $9.9 million, as compared to revenues of $32.7 million and net income of $5.7 million in the third quarter of 2018.
For the nine months ended September 30th, 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 pre-tax 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 pre-tax 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, the net income includes a pre-tax 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 pre-tax unrealized loss on hedges 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 30th, 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 BOE basis, the third quarter 2019 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 30th, 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 Boe basis, the price received for the nine months ended September 30th, 2019 was $49.55, a decrease of 12% from the 2018 price. Production costs per Boe for the three months ended September 30th, 2019 increased to $15.04 as compared to $12 in 2018. Production cost per Boe for the nine months ended September 30th, 2019 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 oil and gas sold. Our production tax expense is directly correlated to the commodity prices received. Our production taxes as a % of revenues remains relatively flat and should continue to be.
Our total depreciation, depletion, and amortization or DD&A, including accretion of asset retirement obligation per BOE for the three months ended September 30th, 2019, decreased to $14.63 per BOE as compared to $18.44 per BOE for the same period in 2018. Our total DD&A, including accretion per BOE for the nine months ended September 30th, 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 DD&A increased by approximately 29% for the three-month period and approximately 46% for the nine-month period ended September 30th, 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 ended 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 BOE 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 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 30th, 2019, was $0.15 as reported. Excluding the $674,000 deferred tax benefit, the pre-tax unrealized gain on hedges of $1.9 million, and the $793,000 non-cash charge for share-based compensation, the income would have been $0.12. 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 pre-tax realized loss on hedges, and the $1 million non-cash charge for share-based compensation in 2018. For the nine months ended September 30th, 2019, the income per share was $0.50 as reported.
Excluding the $5.1 million deferred tax benefit, the 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 non-cash 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 $2.5 million unrealized loss on derivatives, the $6.6 million realized loss on hedges, and the $3.1 million non-cash charge for share-based compensation in 2018. As of September 30th, 2019, we had $366.5 million of the $425 million borrowing base 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 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 30th, 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 30th, 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 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 first and second quarters of 2019, five in the Central Basin and three on the Northwest Shelf.
The average IP for the horizontal wells, all 11 basically, completed and IPs filed in the third quarter of 2019 was 475 barrels of oil equivalent per day, or 101 BOE 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. 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 will lower future operating expense as they will reduce electrical usage, eliminate monthly rental costs on 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 of net production for the third quarter of 2019 was approximately 1,015,000 BOEs, or 11,033 BOE per day as compared to net production of 600,000 BOEs. Again, that's Ring only. That's prior to the Northwest Shelf acquisition. 600,000 BOEs for the third quarter in 2018, and that's a 69.2% increase. Net production of 976,000 BOE for the second quarter of 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 of 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, we proceeded with a full development program starting in 2017. Here we are three years later in excess of 150 wells drilled in the horizontal project that we started in 2016, we're knocking on the door of free cash flow, we expect to be there very soon. 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, 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. The auditors that Randy works with came in and suggested that it'd be more appropriate to account for that as LOE. We had to go back and capture those costs in our LOE for, I believe, it's eight months worth of time. That obviously was a substantial increase in our LOE for this quarter that will 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. As most everybody knows, it's not uncommon in a transition period like that where you're changing operators where there's going to be some confusion with the vendors as far as where they should send their invoices and how they should be processed. 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'll be substantially less than that moving forward. 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 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, 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-$40,000 per pulling job, so substantial savings moving forward. 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're already seeing that, and I think it'll be reflected in future quarters as we move forward once we get 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 is climbing. It has a substantial high fluid level in it, and we're continuing to pump that down at a slow rate. 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. 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. We've adopted some of those practices.
Rather than just gut 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. Hollie's going to talk about the decline curves and the changes that we've seen. One of the things that we've talked about is we've increased the time to reach peak production on the Northwest Shelf 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. Another 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 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. 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. What you'll see is us drilling five this quarter instead of six. That takes into account that.
One other thing I want to address is when we talked about our costs moving forward, when we updated the decline curves, one of the things we did is we also, you'll notice that we cut our cost down substantially. The environment we're in right now, the vendors are very hungry. They're seeing a great deal of angst amongst those vendors, and they're all fighting for our work. Just to give an example, when we were looking at our frack costs earlier in the year, those fracks on our one-mile wells were running anywhere from $900,000-$1 million a 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, where 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. When those invoices now are coming in between $600,000 and $650,000, so you're seeing a substantial savings in these costs. 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 numbers, and we absolutely believe in those.
Any of you analysts out there that any time 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. We have absolute confidence in those numbers. One thing you'll see is we've lowered our costs on the D&C side to $1.9 million on the Central Basin Platform, again, through the savings, mostly through our frack costs. What you didn't see is we did not lower our number on the Northwest Shelf. What we're doing is we're taking advantage of the savings there to increase the size of the frack jobs. The other thing we're doing in that area in particular is instead of renting pumps now, we're buying the pumps, which is a cost of around $150,000 to $200,000.
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. 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. That'll be a substantial cost savings for us moving forward.
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. We've got a lot of savings in there. We did see a substantial cost on the drilling side and the completion side, but we've taken advantage of that to increase the frack and start buying the pumps, particularly on the Northwest Shelf. With that, I'm going to turn it over to Hollie, and she's going to address the economics and the rest of the decline curve changes. Then obviously, if y'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 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 our actual operations, we've continued to refine it. I'm going to 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 frack and buying the pump. We have also included a $200,000 investment at 12 months, and that would be a rod conversion from an ESP to a rod lift, reducing our long-term LOE and OPEX costs 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 peak oil rates coming at 75, a slight increase in gas from 160 to 300, a decline rate that has decreased somewhat simply because of how we're pumping the wells, and a refinement of the b-factor from a 1.5 to a 1.45 has had significant impact on our F&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.
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 occurs at about 12 months. These two were very impactful, once again, into the F&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. At this point, I'm going to hand it back to Danny.
Thank you, Hollie. A couple points I want to make, too, that I wanted to just reaffirm with everybody. The rod conversion that Hollie mentioned is not included in the D&C, but it is included in the economics. Just to be clear, the 1.9 does not include the cost of the rod conversion. We show that on that page at a 1-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. These are solid numbers. They've been reviewed by outside parties, and just want to make that clear to everybody. 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. I'm glad to report that our post-closing is complete. 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. 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 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 of this year, we remain extremely pleased with the quality and the quantity of the tier 1 and tier 2 locations that accompanied 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 really a backseat to our focus for debt reduction, cutting cost, 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. 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 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 a concerted effort to get our story out. With that, Tim, I'll turn it back to you for your closing comments.
All right. Thank you, David. Thank you, Danny, Hollie, and Kelly. Randy, a really good job of laying this out. 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 up, operator, for any questions that our listeners may have.
Thank you. We'll now be conducting a question and answer session. If you'd like to be placed in the question queue, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove a question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, that's star one to be placed into question queue. One moment, please, while we pull for questions. Our first question today is coming from Neal Dingmann from SunTrust Robinson Humphrey. Your line is now live.
Morning. I'll throw an update. My first question is probably for Kelly or Danny. Just given the materially higher estimated PV10 value, I think now you've got up of over $6 million for the Northwest Shelf that you highlighted 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.
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, and 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'll be commitment wells maybe that we have. Even that would be a very minimal number. In fact, everything on the CBP is HBP. We're working through that right now, but really strong focus will be on Northwest Shelf.
No, that makes sense given the returns there. Secondly, question for Tim or Kelly. You guys continue to highlight your free cash flow focus, which you certainly, as you mentioned, are closing in on. I'm just wondering, will this continue to be your primary objective in the coming quarters, once you've achieved this? If so, I'm just wondering, Tim, for you or Kelly, how you think about allocating between free cash flow and production growth, whether we're in a $50 or $60 environment?
That's an excellent question, Neal, 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. Something that this team is working on diligently, and we're going to continue to work on, is the improvement of that balance sheet. 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.
Those are two key priorities for us, and we're going to continue down that road.
Perfect. Thanks. I look forward to all the growth.
Thanks, Neal.
Thank you. Our next question today is coming from John White from ROTH Capital Partners. 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 months' production?
Yeah, John. No, that's a good question. What we've done up there is we have. 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 they are being very gracious in sharing information with us, 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. John, what we've done, typically down on the Central Basin Platform, we have done about a 400 pound per foot frack job. It was appropriate for that particular area. The oil column's a little thinner down there, and really all we're trying to do down there is connect little porosity pods. It's a little different.
Up on the Northwest Shelf, the rock is much more uniform. It's much thicker. Still has good porosity, but we don't see those pods of porosity clear like we do on the Central Basin Platform. It's a much more consistent rock. In visiting with our offset operators, they have, over the years, continued to ramp up their fracs, and they're seeing some really nice success. One of the other things they're doing, well, let me say, they've ramped up to about 800 pounds per foot, and that is the model that we're currently using right now too. We're just now getting our first wells online with that particular frac. Hopefully by the end of the quarter, we'll have some information to share on that with everybody as to what we're seeing.
The other thing is that, obviously, everybody's familiar up in that area with the scale issue that some of the early operations ran into, where they were pulling the well 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. Then run a converter, and then acidize it. It was quite a process. They seem to have eliminated a lot of that issue, as well as sand entry coming back into the well bores by limiting the drawdown per day on those wells. I'm not going to go into exactly what that number is, but they've shared it with us, and we're following that same model. We hope to see that same success.
I know they've had some wells that they've been having substantial run times on well over a year without having to pull the well, which is fantastic. It's also causing the declines to be flatter on the backside as opposed to going up very sharply and coming down very sharply. It really, it just evens everything out. Eliminates problems with scale, eliminates problems with sand. 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. The company that does that will only sell them. They won't even rent them.
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 to 3,500 barrels of fluid a day. Once another well drops down to 2,000, well, I can certainly take a pump that's still running at 80% efficiency, take it out of the bigger well, and move it over to the smaller one. Anyway, it makes a lot of sense to us. Again, look, they've been at this now up in that area for about six, seven years. We've been at it for six months.
We've been 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, in percentage terms of total value, 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, Kelly.
Okay. 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. 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. 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. We weren't real excited about necessarily pairing that off separately.
Of course, you'd have to lease back your ability to dispose of water on top of that, which does affect your overall financial model on the oil side. I would say that the water's worth a little bit less. I can't really speculate what that would be. It's sort of the beauty in the eyes of the beholder. The oil's 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. Again, appreciate the detail. This'll keep David busy during the holidays.
Thank you, John.
Thank you. Our next question today is coming from Noel Parks from Coker & Palmer. Your line is now live.
Good morning.
Morning, Noel.
Just had a couple things. I remember you've talked in the past a little bit about just the spacing you've been drilling up on the Northwest Shelf and a little bit about the parent-child well interactions. I wonder if you just have any updated information on that.
Yeah. Danny, why don't you guys take that?
Yeah, Tim, thanks. 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. 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. Particularly on the Northwest Shelf, it's a very unique geology up there. 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.
What I mean by that is, the rock up on the Northwest Shelf, and this is going to get a little deep, but the rock up on the Northwest Shelf is what we call oil wet, which is an unusual situation. In most cases, you find water, particularly like down on the Central Basin Platform, it's called a water wet reservoir. 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.
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. When that happens, it pushes the oil off the rock. I liken it to when you shake up a Coke bottle and then you pop the lid on it, 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, now you've got the drive, and it pushes the Coke out of the bottle. Exact same thing we see on the Northwest Shelf. As the parent well comes in, its job is to come in and draw the pressures down in the area.
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. Turns out they weren't so crazy. 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. What we're seeing is that on a, say, on a cumulative per-day ratio or a type curve is you see that the child wells are vastly outperforming the parent wells by taking advantage of the initial pressure drawdown.
We don't have that issue that they see in the other areas, especially in a water wet reservoir. If you over-drill 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. As far as just the density drilling that you'll ultimately head toward, it sounds like you've got some motivation to try to err on the side of drilling tighter. Is that fair?
Oh, there's no doubt about it. Look, there's operators in the area that have already down spaced to seven and eight wells per section, and are still seeing very high success rates. Wishbone, in their early stages, commissioned a report from W.D. Von Gonten Engineering, which is a very well-respected engineering firm out of Houston. 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.
Right. In your inventory, what's the density you're assuming?
Most of ours well, 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. That's something we've got in our pocket if we need it later.
The current economics reflect six, though.
Yes. Current economics, yeah, reflect six.
Great. Just one last thing. I just didn't quite catch a couple of numbers when you were talking about. You were saying that for the rod pumps, a pulling job ran $20,000-$40,000, and that's as opposed to the ESP cost.
Yeah
the higher cost for those?
Right. No, pulling the ESP wells runs about $200,000 per well.
Okay. Maybe like 80% cheaper really.
Right. It's an 80% reduction in future pulling costs.
Okay. Okay, great. That's all for me. Thanks.
Thank you. Our next question today is coming from John Thomas, a private investor. Your line is now live.
Thank you. Well, congratulations 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 11,000 barrels a day , at $50 a barrel, that translates into about $200 million annually. It's great to hear the projections for cost 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, 15 months with stock price evaluation, you have to start thinking out of the box. My proposal is a simple one.
With a $200 million 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. It could be a modest dividend. It could be $1 million paid out over the year, which would equate to about $0.15 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. All this great work has not shown any profit or potential for the investor. I would like, first of all, for you folks to consider paying a dividend.
I'll give you some thought on that. My second question is that you had a private investor that recently purchased 8 million shares. I would like to have your thoughts and comment on that. Thank you.
Well, thank you, John, and good questions. This is Tim. 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 supporter, obviously. 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.
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. 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, one would say, "Well, what about a stock buyback?" What about something else to consider? Maybe a dividend. Well, 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.
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. 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 million shares, but about 5.5 million 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 are in general conversations, and we welcome their position and their investments just like we do the rest of the 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 the stockholders simultaneously. 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.
Morning.
Looks like you're seeing some good results with the workover 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 D&C development, especially considering these new type curves and the favorable results you're getting on the Northwest Shelf?
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. As Danny noted earlier on the call, we're working on that now. Why don't you go ahead and shed a little light on that, Danny?
Sure. No, look, those are ongoing side-by-side processes. Obviously, what we do is we look at how many wells we want to drill per quarter, per year, and then we work the rest of the budget around that. We are doing a substantial number. Far this quarter, we've done seven rod conversions. 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 Hollie 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 in the Central Basin Platform in particular, as we move forward with the conversions. That's exciting to me moving forward. It makes sense to run both of those in parallel.
We do set a limit on the number of rod conversions we're going to do because the primary focus is still drilling. I'd say drilling is one, and rod conversions and the workovers are 1B. 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 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 hedge program. I've noticed that you're letting your current hedges sort of run off for 2019. You haven't added anything for 2020. Do you have any thoughts about that?
Yeah. As a matter of fact, David, you're right. The 2019s will be running off, but we actually have paid a lot of attention to that, and we've just recently added for 2020, and we continue to work on that.
Thank you. We've reached the 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. 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. Of course, Bill Parsons, who talked to a number of you, is available as well. 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.