Greetings and welcome to the Ring Energy, Inc. conference call to discuss the 2019 second quarter financial and operating results. At this time, all participants are in a listen-only mode. The question and answer session will follow the formal presentation. You can ask a question by pressing star one on your telephone keypad. 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. I would now like to turn the conference over to our host, Mr. Tim Rochford, Chairman of the Board of Directors. Thank you, sir. You may begin.
I'd like to thank and welcome all listeners for joining us today on our 2019 second quarter and six months financial and operations conference call for Ring Energy. Joining me on the call today, in addition to myself, again, Tim Rochford, Chairman of the Board, will be Kelly Hoffman, our Chief Executive Officer, David Fowler, our President, Randy Broaddrick, our Chief Financial Officer, Danny Wilson, Executive Vice President of Operations, Hollie Lamb, Vice President of Engineering, and of course, Bill Parsons, who joins us from investor relations. Today, we'll cover the financials and the operations of the second quarter and six months ended June 30, 2019. We will review our results and provide some insight as it relates to the current progress thus far in the third quarter of 2019.
At the conclusion of the review, we'll turn the call back over to the operator, and we're going to open up for any questions that you may have. Now, I'm going to ask Randy Broaddrick to give us a review on the financials. Randy?
Thank you, Tim. Before we begin, I would like to make reference that any forward-looking statements which may be made during this call are within the meanings 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, August 7, 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 June 30, 2019, the company had oil and gas revenues of $51.3 million and net income of $12.4 million, as compared to revenues of $29.9 million and net income of $4.7 million in the second quarter of 2018.
For the six months ended June 30, 2019, the company had oil and gas revenues of $93.1 million and net income of $23.5 million, as compared to revenues of $59.8 million and net income of $10.4 million. For the three-month period of 2019, the net income includes a pre-tax unrealized gain on hedges of $1.5 million, acquisition-related costs of approximately $600,000, and a deferred tax benefit adjustment of $600,000. Without these items, net income would have been approximately $11.6 million. The three-month period of 2018 net income includes a pre-tax unrealized loss on hedges of $1.1 million. Without this item, net income would have been approximately $5.6 million.
For the six-month period of 2019, the net income includes a pre-tax unrealized gain on hedges of $1.2 million, acquisition-related costs of approximately $4.1 million, and a deferred tax benefit adjustment of $4.5 million. Without these items, net income would have been approximately $21.3 million. The six-month period of 2018 net income includes a pre-tax unrealized loss on hedges of $1.9 million and an additional tax provision of $1.2 million. Without these items, net income would have been approximately $16.3 million. For the three months ended June 30th, 2019, our oil price received was $56.86 per barrel, a decrease of 8% from 2018, and our gas price received was $0.95 per Mcf, a decrease of 69% from 2018.
On a per Boe basis, the second quarter 2019 price received was $51.95, a decrease of 9% from the 2018 price. For the six months ended June 30th, 2019, our oil price received was $53.74 per barrel, a decrease of 12% from 2018, and our gas price received was $1.51 per Mcf, a decrease of 53% from 2018. On a per Boe basis, the price received for the six months ended June 30th, 2019 was $51.95, a decrease of 9%. I'll double-check that. I apologize. Production cost per Boe for the three months ended June 30th, 2019, decreased to $11.71 as compared to $12.70 in 2018. Production cost per Boe for the six months ended June 30th, 2019, decreased to $11.24 as compared to $11.97 in 2018.
We are still evaluating the ultimate impact the Wishbone acquisition will have on our ongoing production cost per BOE, but we expect it to be at or below our historical average. Production taxes are based on values of oil and gas sold, our production tax expense is directly correlated to the commodity price of receipts. Our production taxes as a percentage of revenues remain relatively flat and should continue to be. Our total depreciation, depletion, and amortization, including accretion of asset retirement obligation, per BOE for the three months ended June 30th, 2019, decreased to $15.02 per BOE as compared to $17.81 per BOE for the same period in 2018. Our total DD&A per BOE for the six months ended June 30th, 2019, decreased to $14.99 per BOE as compared to $17.32 per BOE for the same period in 2018.
Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts. As to total amounts, our DD&A increased by approximately 59% for the three-month period and approximately 56% for the six-month period ended June 30, 2019, versus the comparable periods in 2018. Our overall general and administrative expense increased $1.7 million for the three months ended and $5.6 million for the six months ended June 30, 2019, as compared to the same period in 2018. However, we incurred approximately $4.1 million in acquisition-related costs during the six-month period, of which approximately $600,000 was during the three-month period. Without these additional costs, the increases from 2018 are approximately $1.2 million for the three-month period and $1.5 million for the six-month period.
Excluding the acquisition-related costs on a per BOE basis, this equates to an increase from $3.59 in 2018 to $3.96 in 2019 for the three-month period, and a reduction from $6.01 in 2018 to $4.12 in 2019 for the six-month period. Second quarter 2019 development CapEx was approximately $51 million, along with the approximately $46 million from first quarter of 2019. This puts the six months development CapEx at approximately $97 million. These amounts exclude acquisition-related costs and the incursion or assumption of asset retirement obligations. On a per BOE basis Sorry, on a diluted basis rather, the income per share for the three months ended June 30th, 2019, was $0.18 as reported.
Excluding the $600,000 deferred tax benefit, the pre-tax unrealized gain on hedges of $1.5 million, the $600,000 acquisition-related costs included in G&A, and the $809,000 non-cash charge for share-based compensation, the income would have been $0.17. This is compared to income per share of $0.08 as reported, or $0.13 per share, excluding the $1.1 million unrealized loss on hedges, the $2.4 million pre-tax realized loss on hedges, and the $1 million non-cash charge for share-based compensation in 2018. For the six months ended June 30th, 2019, the income per diluted share was $0.36 as reported. Excluding the $4.5 million deferred tax benefit, the pre-tax unrealized gain on hedges of $1.2 million, the $4.1 million acquisition-related costs included in G&A, and the $1.6 million non-cash charge for share-based compensation, the income was $0.34.
This is compared to income per share of $0.17 as reported, or $0.24 per share, excluding the $1.9 million unrealized loss on derivatives, the $3.9 million realized loss on hedges, and the $2.1 million non-cash charge for share-based compensation in 2018. As of June 30th, 2019, we had $360.5 million of the $425 million borrowing base drawn on our credit facility and had cash on hand of $10.6 million. For the three months ended June 30th, 2019, we had adjusted EBITDA of approximately $33.3 million, or $0.49 per diluted share, compared to approximately $17.3 million or $0.28 per diluted share for the same period in 2018. For the six months ended June 30th, 2019, we had adjusted EBITDA of approximately $57.5 million or $0.87 per diluted share, compared to approximately $36.5 million or $0.61 per diluted share for the same period in 2018.
With that, I will turn it back to Tim.
All right, Randy. Thank you. Appreciate that. I'm gonna ask Kelly to give us a recap on the second quarter overview and operations. Kelly?
Thanks, Tim, and thanks everyone for joining us on the call. In the three months ended June 30th, the company drilled 13 new horizontal San Andres wells. Our Central Basin Platform asset, we drilled seven new horizontal wells, five one-mile horizontal wells, and two one-and-a-half-mile horizontal wells. On our newly acquired Northwest Shelf Property, we drilled six new horizontal San Andres wells, four one-mile horizontal wells, two mile-and-a-half horizontal wells, and we're in the process of drilling two more at the end of the quarter. Of the 13 wells drilled, four were waiting on completion. That was two Central Basin Platform and two Northwest Shelf wells. Seven were drilled, completed, and are in various stages of testing, five on the Central Basin Platform and two on the Northwest Shelf. Two were drilled on the Northwest Shelf, completed, finished testing, and had initial potentials as filed.
The first one was the Bruce E. Gentry, Jr. #647H. Had an IP of 359 barrels of oil equivalent per day. That calculates to 88 BOE per 1,000 foot. The Sooner #662H was the second well, A2H, hit an IP of 767 barrels of oil equivalent a day, which is 181 BOE per 1,000 foot. We're very pleased with the preliminary results we're seeing on the Northwest Shelf and the continued results we're seeing on our Central Basin Platform assets. All our forecasts are based on average type curve IPs of 86 BOE per 1,000 foot, and the average IP on all of our horizontal wells continues to exceed 100-plus BOE per 1,000 foot. As a result, net production for the second quarter of 2019 was approximately 976,000 BOEs. That equates to about 10,725 BOE/PD. That's on a per day basis.
This is the first time the quarterly operations update combines both the Ring and the newly acquired Northwest Shelf properties. June 2019 average net daily production was approximately 10,800 BOEs per day. A side note for those listeners on the call today, I want everyone to know that we had previously reported, if you'll remember, a differential of approximately $5 per barrel. However, July came in at three, and when we're looking at the snapshot of August up to this point, it is also looking like around $3, maybe slightly less going forward here. We're feeling pretty strong about that. With that, I'm going to turn it over to Danny and Hollie to give you some current update on operations and a little more detail on our plan moving forward. Thank you.
All right. Thanks, Kelly, and thanks everyone for being on the call. I want to start out by giving you an update on a few of our existing wells. Out in the Delaware Basin, our Brushy Canyon horizontal wells continue to have impressive production, in particular the Eugene 1H and 2H, which are located in our northeast part of our acreage. They continue to produce at a combined rate of 350 barrels of oil per day and 2.3 million cubic feet of gas. Since the beginning of the year, these two wells have combined production of over 105,000 BOE, of which 80% is oil. On our North Gaines acreage, our two horizontal San Andres wells, the Ellen B. Peters number 3H and 4H, continue to produce at a combined rate of 150 barrels of oil per day.
To update you on our Q3 activity, we are currently drilling our sixth and final well of the quarter. We should be finishing it up by the middle of this month. All the wells drilled this quarter, as well as those planned for next quarter, have been drilled on our newly acquired Northwest Shelf acreage. We are drilling this area for two reasons, the first being that we have fulfilled our drilling obligations on the Central Basin Platform for the year, and the second reason is due to the early results we are seeing on the Northwest Shelf. As Kelly mentioned, our first two wells on the Northwest Shelf IP'd at 359 and 767 BOE per day. Results like this are exactly why we bought the Wishbone acreage. The acquisition checks every box we were looking for in a project area.
It's a conventional reservoir with a dolomite that's a dolomite and not a shale. It's at a shallow depth of approximately 6,000 feet. It has low development costs and yields high returns. Most importantly, it has plenty of running room. As pleased as we are with our CBP properties, we're even more encouraged by the early results we are seeing on the Northwest Shelf, that is why we plan to do the bulk of our drilling in this area over the next year. Just to be clear, we are drilling on the Northwest Shelf because the results are exceeding our expectations, and we have fulfilled our obligations for the year on the CBP. I also want to walk you through the thought process behind the changes we have made to our 2019 capital spending budget, which we announced in late July.
Our main focus was on 3 key points as we worked through the revised budget. First, we were concentrated on obtaining cash flow neutrality as quickly as possible. Secondly, we were managing our debt, and third, maintaining modest year-over-year growth. After closing the Wishbone acquisition in early April, we released a preliminary budget of $154 million, which included the drilling of 50 horizontal wells for the year. In the same breath, we reiterated that this was a preliminary budget and that once we had a chance to operate the properties for a few months, we would release an updated budget, which would likely be higher. Our internal estimates were that we would likely have an increase of around 15%, which would raise our spending for the year to $175 million-$180 million.
Once we took physical control of the properties, we realized there was an even greater backlog of opportunities that needed to be addressed. This was largely due to the lack of capital spending by Wishbone while they were marketing the property and subsequently closing the sale. This lack of spending occurred over a six-month period from October of 2018 until the close in early April of this year. Once we evaluated the work that needed to be performed, we realized that most of the work fell into four main categories. The first was the need to perform workovers on wells which were shut in or had reduced production due to scale, iron, and sand accumulation in the wellbore. Second, we had wells with ESPs which needed to be properly sized. Third, we had wells which needed to be converted from an ESP to a rod pump.
Fourth, infrastructure projects to increase electrical reliability and the streamlining of the wastewater handling systems to allow for future drilling activity. As we completed our project evaluation, we could see that if we were to move forward with the original drilling program and perform the additional work we had identified, that the budget was going to increase substantially beyond the anticipated 15%. At that time, we took a step back and looked at our options. We could move forward with the original 50-well drilling program and further increase our budget over the anticipated 15%. This could have jeopardized reaching two of our three goals, that of getting to cash flow neutrality and managing our debt.
We could go with the second option and scale back the drilling enough to maintain modest year-over-year growth, get our house in order by working over wells, and rightsizing our production equipment, either through downsizing of ESPs or converting to rod pumps where possible. We chose the latter option to ensure that we could meet all three of our stated goals. I'm going to turn the discussion now over to Hollie Lamb, our Vice President of Engineering, and she's going to go through the reasons and the economics behind performing these workovers.
Thanks, Danny. I'd like to focus on the economics of the workovers and optimization. Let's start with the workovers. The workovers are associated with some type of downhole obstruction in the lateral portion of the wellbore. These downhole obstructions are not predictable. They cannot be scheduled, and they don't happen on every well. They can be identified by various means, including changing in their production profile. They can consist of a combination of frac sand and scale, and that scale can be either iron-based or calcium sulfate. Based on our experience, these occurrences involving scale obstructions are a single event occurrence in a wellbore history. These events happen early in the well's life and are generally associated with the maximum pressure drop from the higher pressure formation to the lower pressure wellbore. These materials can be mechanically drilled out of the wellbore, and then the wellbore can be chemically treated.
In many cases, these wells return to a normal production profile after the intervention has taken place. In some cases, the production actually exceeds the previous profile. In both areas, we have seen rates of return in excess of 100% with payouts of less than one year. These compare very favorably with our metrics on our new drill wells. Let's switch gears now and talk about optimization, specifically optimizations of our pumping equipment. Early in the life of a well, we install an electric submersible pump, or ESP, which is sized to move 3,000 to 4,000 barrels of fluid a day. As a well naturally declines, it makes sense to change out these ESPs to smaller ESPs, reducing the horsepower draw, electrical demand, and also extending the runtime of the pump, since it reduces the wear and tear on the right size pump.
Eventually, these wells will decline to a point where it makes sense to replace the ESP with a rod pump. Once this occurs, we see tremendous benefits. The continued reduction in LOE as much as 50% due to electrical usage. We also have substantial reduction in equipment maintenance as well, since now most of the pumping equipment is located on the surface as opposed to being downhole. The aforementioned benefits are eclipsed by the reduced cost on pulling these wells going forward. A typical pulling job for a repair on an ESP runs around $200,000-$250,000. A typical repair job on a rod pump is between $20,000 and $40,000. This translates into an 80% reduction every time we work on that well. The initial conversion to rods costs between $150,000 and $250,000.
This translates to an LOE savings every month and a lowered cost on well servicing going forward. This conversion pays out the first time we pull a well. The lower LOE extends the economic life of the well, and by extension, adds economic reserves. Based on these benefits that we have laid out for both the workovers and optimizations, there is no doubt this is the right decision and will return dividends tomorrow and for many years to come. At this point, I would like to hand it back to Danny to wrap up the operational update.
Thank you, Hollie. To recap our budget discussions, we started with three key goals. First, reaching cash flow neutrality as quickly as possible. Second, managing our debt. Third, still maintaining modest year-over-year growth. In early April, we took over physical control of the Wishbone property. We immediately started drilling on the property and issued a preliminary budget. We analyzed the properties, identified the opportunities in four key areas. First being the working over of underperforming wells. Second, rightsizing of existing ESPs to lower costs. Third, converting to rod pumps where possible, thereby reducing lifting costs, which yields increased EURs, and most importantly, drastically reduces future pulling costs, which ultimately reduces future CapEx and future LOE. Four, performing infrastructure projects to streamline water handling and facilitate future drilling.
Finally, in late July, we issued a revised budget which lowered our CapEx and greatly increased the certainty that we could meet all three of our key goals. With that, I'm going to turn it over to David to cover our leasing and merger and acquisition discussion.
Well, thank you, Danny. As you are all aware, we've had an active and exciting second quarter with the acquisition of the Wishbone assets that was truly transitionary for Ring as it doubled the size of the company. The assets were a perfect fit for our core asset base and established Ring as a consolidator on the platform and now on the shelf. Besides being a great acquisition for Ring, we were able to buy the assets during a distressed oil market, or what we refer to as a buyers market, for a price that was essentially a PDP value. In short, this asset's going to provide Ring and our shareholders a lot of value and growth for years to come. Excuse me.
Regarding our leasing, since we now have an acreage position on the Platform and Shelf of almost 120,000 net acres, our leasing activity is somewhat limited and more concentrated in a few target areas on both the Platform and the Shelf that is mostly focused on grossing up our net acreage positions, offsetting our upper tier locations. The land department has done an excellent job of simulating the Wishbone leases into our system while they work diligently to stay ahead of operations and the drilling rig program. Regarding A&D, since the beginning of the year, numerous companies have taken their assets to market across the Permian and elsewhere and have had failed sales indicating that we're still in a retracted A&D market. The bid-ask from buyers and sellers continues to be significant enough to make it difficult to get deals across the finish line.
Hopefully soon, we'll see the market conditions improve, and we'll see the door open to more M&A activity. With our ongoing effort to differentiate ourselves from the non-conventional shale operations in the Permian, or operators in the Permian, what I refer to as being in the shadow of the shales, we're attending several conferences and NDRs between now and the end of the year to tell our story. I hope that I'll see a lot of you there. With that, I'll turn it back to Tim for closing comments.
All right. Thank you, David, and Danny and Hollie and Kelly and Randy. Good job, guys, reviewing everything. Now I think what we'll do is just turn it over to the operator, because this will now officially conclude the 2019 second quarter and six-month review. Operator, I'll turn it back to you, and let's open it up for questions that they may have.
Thank you, sir. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. Once again, to ask a question, press the star key followed by the one key on your telephone keypad. You may press star followed by two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. Our first question comes from John White with ROTH Capital. Please proceed with your question.
Good morning, congratulations on a very solid quarter.
Thank you, John.
I really appreciated Hollie's detail on the workovers and the pump optimization. That was great new information. Now you're on a one-rig program, and you're going to do a lot of rework and refurbs on existing wells, you say, on both the Northwest Shelf and the Central Basin. Do you have a split of how many on each of those properties?
In terms of the workover and the rod conversions, John? Is that-
Yeah.
Okay.
What's the workover split between the Shelf and the Central Basin?
Yeah. Danny and Hollie?
Yeah, you bet. John, that's a great question. It's really almost about a 50/50 split. There's not either area that really is outshining the other as far as what needs to be done. Again, the main focus on the Central Basin Platform is the rod conversions. Those are a little older properties. They've been producing longer, and we're diligently working on getting those converted over. Up on the Northwest Shelf, it's more of a combination of the two things, well, three things, the ESPs, making sure those are the right size, cleaning out the wellbores and returning those to production, and then the rod conversions. The money's pretty evenly split, but there's a little bit of difference between the two areas as far as the work that's being done.
I appreciate that. Makes sense on the Central Basin going to mostly rods due to the age. Kelly, did you mention what production was during the month of July?
No, I did not.
All right.
John, I think what was referenced in July was the differential that we were seeing for July.
It was.
Okay. Thanks a lot. I'll turn it back to you.
Thanks, John.
Our next question comes from Jason Wangler with Wunderlich Securities. Please state your question.
Morning, guys. You mentioned in the prepared remarks about moving to the Northwest Shelf the rest of this year. As you look at the program, if it's a one-rig program next year, could you maybe talk about how you see the activity between the two properties?
Sure. Danny, do you guys want to grab that?
Yeah, you bet. To start out with, on the Central Basin Platform, most of our drilling is focused in the area that we recently purchased from Tesoro on the university lands acreage down there. We did that acquisition right before the Wishbone acquisition. With the university lands, we have a minimum footage that we have to drill. Next year, it looks like we're probably going to need to drill about eight to nine wells down there. That's what we'll do in that area, and then the rest of the wells, and we haven't come up with a final number yet, but it's probably going to be in the 30-ish range. That includes the eight wells on the CBP. Something in that range will probably be the remainder of those will be up on the Northwest Shelf.
Okay. I appreciate it. Thank you.
Our next question comes from Neal Dingmann with SunTrust Robinson Humphrey. Please state your question.
Morning, all. Tim, maybe for you or Kelly. I don't need anything too specific here. I'm just wondering, could you give how you all view the magnitude or list the potential of the non-core asset sales? I guess where I'm going with that is I'm just wondering, general levels, if some sale, maybe once you give that answer, how that might play into if you would think about going to a second rig or so, because you're obviously pretty cognizant of, as you should be, of not going too high on the debt. Just wondering, based on what you tell us, the magnitude or potential timing of these other non-core sales, the second part of that question would be how that could play into a potential second rig for the program sometime next year.
You bet. Certainly. There's no question between the platform and now the Northwest Shelf, we have plenty to do for years to come, even if you were to deploy multiple rigs. That reshift the focus back to what about Delaware? The Delaware is a fine asset, but really it has taken second or third place in terms of the line items of priority. One would seem to think is that an opportunity to possibly move off and improve the balance sheet, have some cash available for a future acceleration, et cetera. The answer to that is likely yes. There's no official marketing effort at this time as it relates to the production profile. There has been some thought given to the midstream on the SWD side. In fact, we've had conversations with interested parties, but we've done nothing yet as an official move.
That's something we do keep in mind as we go forward. You're right, Neal, there's two things that would become of that. One is to improve or tidy up the balance sheet, and the second, provide a cash cushion, if you will. If in fact commodity space improves as we go into next year, accelerating to a second rig would certainly boost that opportunity.
Pretty good. Just one last one, probably for Danny or Hollie. You gave a good list of the reasons for the workovers, and John, I appreciate that. I'm just wondering, I think some thought for Kelly, for any of you all, that this was more of a regular item, and I'm just wondering if you could just talk about, as you see on a go forward starting next year and so. When you think about workovers, is this just more on a case-by-case basis? Is this something that you'll think you'll need more often than not? Maybe if you just explain that to us, I think that would help. Thank you.
Yeah, Neal, that's a good question. One thing people tend to forget is that we operate over 700 wells. It's not just these few that we continually talk about. There's always projects to be done. There's always going to be a certain amount of our budget that's going to be allocated to working on existing wells. Moving forward, there's always going to be projects. We don't really ever know typically when a well's going to go down and need to be worked on. Do I think it's going to be this magnitude? Possibly, but probably not as much, though, because we did have a big backlog that we had to deal with and are still dealing with moving forward. I think we'll largely have that handled by the end of the year.
Moving into next year, I think the pace will slow down and even out a little bit more.
If I could just sneak one last one, just based on sort of CapEx, I know you certainly don't have, Tim, you and Kelly don't have any guidance out for future CapEx, I'm just wondering from broad terms, when you think of either, I'll throw workovers into potentially just non-typical D&C as I would infrastructure, how would you think about the non-D&C spend next year versus this year? I got to think it would be down a bit.
A bit is right on. I don't think there's any question. I think Danny did a good job of saying, listen, between the backlog that already started to build on the platform and along with the backlog that came along with the inheritance of the Wishbone because of just no activity for a number of months, that is a bit overwhelming, but it's very manageable. Once we catch up with that, as Danny said, I think as we go into next year, and as Hollie carefully pointed out, you can't always predict the timing of this, and it doesn't happen to every well.
I think next year, there's no question as we put out our CapEx, there's going to be a healthy line item for that type of activity, but I don't think it's going to be anywhere near to where it's at today in terms of ratio versus drilling and completion.
Great. Thank you all.
Our next question comes from John Lane with Lane Capital Markets. Please state your question.
Hey, Tim, how are you?
Good, John.
Congratulations on a fantastic quarter. I'm sure that everybody on this call is smart enough to understand that the stock price is nowhere relevant to what's going on internally with the company and the tremendous asset you've built here or are continuing to build here. Can you just discuss a little bit about why you think the price of the stock is getting hurt as bad and maybe a little discussion in regards to some of the insider buying that's been taking place that doesn't seem to hit the press anywhere?
Yeah, you bet, John. I'd be happy to remark on that. I think I'll start off with letting Kelly address that, and then I'll follow up.
Thank you.
No, John, I appreciate it. Look, there's no question that there's been sort of an increased level of shorts and things that are out there in the marketplace, and we've taken note of that, and we've started to talk internally about it, and we've even had some conversations with outside people, but not to a point where, of course, it would be any type of distraction for us. We're maintaining our focus on getting to those items that Danny was talking about and the free cash flow and all that. We do keep an eye on those things, and we are taking aggressive approaches to it to the extent that we can. I would say that going forward, I think, the combination of that, along with some computer selling and some things like that, we've probably been a bit of the victim for that.
I would say that looking at us this year, we've taken a lot of aggressive approaches to cost management, to concepts like this revision on our budget was a very aggressive approach to, again, protecting the balance sheet, getting us the cash flow neutrality, and still showing growth. We're listening to the street closely, and we're trying to pay as much attention to those items as we can, and be very careful and thoughtful about our approach.
John, just as a follow-up with reference to your question. As you know, and as everyone on this call knows, there are times in the life of management in the company during the course of a year that we have our lockouts or blockout periods when it really prevents us from being active at all in the stock. That was a considerable amount of time that took up last year, and the same is the case this year. We did have some insider buying, as you know, just a number of weeks ago, and then that window closed very quickly. I won't elaborate on that, but as David Fowler mentioned in his comments, there are a number of opportunities out there on the platform and on the shelf, and we look at these. Anytime there's any discussion, we're very careful.
From our own internal policies, we're very careful with reference to our own personal activities pertaining to the stock. Right now, there is just absolutely no question where this stock trades versus our peers. I follow probably 35, 40 different companies pretty closely, and I think you'll look and see that 80%, probably closer to 90% of those companies are all trading at 52-week lows. Some have been beat up more than others, and we fall into that category. There's no question that this stock, in our opinion, is grossly undervalued and for a number of reasons. You can do the metrics and figure that out. Whether you're doing multiples or you want to throw out the old NAV style of valuation, fine, throw it out. Look at the multiples. Look at the projected.
Just imagine what EBITDA can look like based on this last quarter and going forward. You start doing some multiples of that. You look at the production profile. I think everyone would agree that even in the absence or factoring in the debt component, that it's a screaming buy. Enough of beating that drum. I hope that answers your question, John.
Yeah. You've always been a shareholder focused, and I know that's never going to change. I know that sooner or later, the stock price will catch up to what you've really got going, and I just appreciate your constant effort to make this company stronger and better. Thank you. Thank you, Kelly, too.
All right.
Thank you, John.
Our next question comes from Mark Levy. Please state your question.
Thank you. I appreciate the opportunity. Based on the conversation where the Delaware holdings have slipped to a second or a third-degree priority, and mitigating debt is an issue, is there a general sense of the valuation of that Delaware Basin holding, generally?
Danny, you might want to reflect on that, or Kelly. I think we can all have our opinions of that. Just let me start off by saying this, Mark: we haven't formally started sitting down and drawing circles in terms of where we think, what kind of values. I think we all have ballpark values where that might be, and I don't think we're going to, in this discussion today, talk about those numbers, but maybe giving an overall feel of things. Maybe Danny, you take the first swipe at that.
Obviously, we're very happy with the area out there. We love the potential for the horizontal Brushy Canyon. We think that has tremendous upside. Unfortunately, it's hard for that area to compete for the dollars when we're looking at the returns we're seeing over on the Northwest Shelf. Although they're similar, it's still a little bit different. As far as the value of that, I don't know that we really have a feel for what the market value might be. Internally, we have reserve values on it, obviously. The market's been all over the place. With that, I'll let Kelly comment.
I was going to add that when we talk about that asset out there, people tend to think of it from just an oil and gas standpoint. Frankly, there's a substantial asset out there on top of it. It's called our saltwater disposal system, which we have done a great job of building. Hollie and Danny have done a wonderful job with the troops of building that from north to south, creating multiple redundancies. Frankly, we've had people from a private equity standpoint come into our office a number of times over the past 2 years, actually maybe a little longer than that. They throw around a lot of different numbers, Mark. I don't know what the value of it is today. A couple of years ago, people were tossing around $20, $30, and $40 million numbers.
I couldn't guess at what it would be today, but I do believe it would be additive to the concept of the oil and gas sale if we did decide that it was something that we could market, or someone came into the office and threw something at us that really we couldn't pass up as an idea. It probably would include an upcharge, so to speak, for that system. We're hopeful that that maintains that capacity going forward, and we'll see what happens.
Fair enough. Thank you. The only other question I have, and it's probably not fair, and it's across all strata. Is there an average general decline curve that would be generally considered appropriate? I know that's not fair, but I'm curious.
For the company?
Yeah.
Danny, Holly?
We do have the type curves out on our website for each area, so I would just suggest that you look at that.
Fair enough.
We don't really have a combined company-wide one.
Okay, thank you.
Our next question comes from Richard Tullis with Capital One Securities. Please state your question.
Thank you. Just one or two quick questions, maybe more for Danny. What's the outlook, given the one rig and the planned workovers and the swapping out of the pumps, what do you expect the production exit rate 2019 could look like, Danny? Continue with one rig into 2020, what do you expect the production growth profile could look like next year?
Richard, I think internally, we're looking at a number in the mid-11,000. Could be a little higher, could be a little lower than that for our exit rate for this quarter. Obviously, drilling fewer wells is going to, as I've mentioned in my report, we're trying to go for modest growth, but the key focus is still on getting cash flow neutral and managing the debt. I would say that, and then I would think next year, you could probably look at anywhere from a 3%-8% increase, something in that range. That's what our models are indicating.
That would be based on one rig, right, Danny?
That's based on one rig.
That's helpful, Danny. Just lastly, maybe even for Tim or Kelly. You've stated the target of the free cash flow neutrality by year-end this year. Does that hold for next year as well for the full year?
It does.
Okay. All right. Well, that's all from me. Thanks so much.
Thank you, Richard.
Thank you. Just a reminder, to ask a question, press star followed by one on your telephone keypad. Press star followed by two to remove yourself from the question queue. Our next question comes from Ivan Zwick. Please go ahead with your question.
As a follow-up to the gentleman that asked a question about the stock price, can you tell me what the net asset value per share of the company is?
The net asset value?
Yes.
Are you basing that on the PV-10 of total proved?
Yeah, right.
Okay. Randy, do you have that handy, or maybe Holly, you have that handy? Total proved combined assets. Randy?
Give me just a moment. Okay.
Ivan, just to be clear, You're making reference to 1P and not 3P, is that correct?
I guess, right. Yeah. I think the stock price is pretty ridiculous myself.
We would agree. When you look on our website, I think we have a slide, it seems like it's maybe number 24. I think it's in and around that $1.1 billion range, if I'm not mistaken, on a PV-10 basis.
Okay. All right.
Hollie, I don't have that handy. Did you?
Okay.
I was going to add that you want to give consideration to the stock price, of course, when you do that. I'm sure there's a footnote there on that page which refers to what we used in that calculation.
Okay. I thought you were having a fine quarter.
Good to hear.
Thank you.
Thanks, Ivan.
Thank you, ladies and gentlemen. There are no further questions at this time. I'll turn it back to management for closing remarks. Thank you.
Okay. Thank you, operator. We appreciate it, and thank you everyone for taking the time. We know, again, it's that busy time of the year with a lot of reporting, a lot of other companies having their calls as well. Thank you, and as always, our door is open, and of course, Bill Parsons, Investor Relations, is happy to hear from you, and we'll look forward to talking to you along the way. Thank you.
Thank you.
Thank you.
This concludes today's conference. All parties have been disconnected. Have a great day.