Ring Energy Inc (REI) 2020 Q2 法說會逐字稿

Greetings, and welcome to the Ring Energy, Inc. 2020 Second Quarter Financial and Operating Highlights Conference Call. (Operator Instructions)

Please note that this conference is being recorded.

I will now turn the conference over to your host, Mr. Tim Rochford, Chairman of the Board of Directors of Ring Energy. Thank you, sir. You may begin.

Thank you. Thank you, operator. And I want to thank all of our listeners today for the 2020 second quarter financial and operations conference call for Ring Energy, Inc. Again, I'm Tim Rochford, Chairman of the Board. Joining me on the call today is Kelly Hoffman, our CEO; David Fowler, our President; Randy Broaddrick, our Chief Financial Officer; Daniel Wilson, Executive VP and Head of Operations; Hollie Lamb, Vice President of Engineering; Matt Garner, who's VP of Land; and Bill Parsons, Head of Investor Relations.

So today, we'll provide a quick, concise overview of the financial and operational results for the 3 months as well as the 6 months ended June 30, 2020. And as we have done in the past 2 quarters, we'll spend the majority of this call identifying, discussing and summarizing the factors that directly affect the current and future operations of your company. At the conclusion of the second quarter review, we'll turn it back over to the operator, and we'll open it up for any questions that you may have.

Now with that said, I'm going to turn this over to Randy Broaddrick for just a brief financial overview. Randy, please?

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 Monday, August 10. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com.

For the 3 months ended June 30, 2020, we had revenues of $10.6 million, net loss of $135 million and loss per diluted share of $1.99. This net loss included a pretax unrealized loss on hedges of $26.8 million, $147.9 million in ceiling test impairment and $1.3 million in stock-based compensation expense. Without these items, after the effect of income taxes, our net income would have been approximately $1.5 million or $0.02 per share.

For the 6 months ended June 30, 2020, we had revenues of $50.2 million, net loss of $91.2 million and loss per diluted share of $1.34. This net loss included a pretax unrealized gain on hedges of $20.3 million, $147.9 million in ceiling test impairment and $2 million in stock-based compensation expense. Without these items, after the effect of income taxes, our net income would have been approximately $9.2 million or $0.14 per share. The unrealized gain or loss on hedges is recorded because the value of derivatives changed as a result of the changes in oil prices. The ceiling test impairment is the result of a reduction in the value of our reserves as a result of a reduction in oil prices.

During the 3 months ended June 30, 2020, we had $9.7 million in net cash flow and $1.8 million in capital expenditures for a post-CapEx positive cash flow of approximately $7.8 million. During the 6 months ended June 30, 2020, we had $33.6 million in net cash flow and $17.9 million in capital expenditures, for a post-CapEx positive cash flow of approximately $15.8 million.

For the 3-month period, we had oil sales of 429,751 barrels and gas sales of 417,491 Mcf for a total of 499,333 BOE. Our received prices were $24.23 per barrel of oil, $0.53 per Mcf of gas for $21.30 per BOE. For the 6-month period, we had oil sales of 1,285,354 barrels and gas sales of 1,183,052 Mcf for a total of 1,482,528 BOE. Our receipt prices were $38.16 per barrel of oil, $0.98 per Mcf of gas for $33.87 per BOE.

The differential between our oil price received and WTI averaged approximately $2.50 per barrel. This would have been higher had we not limited our sales during the month of May. We limited sales by curtailing production from late April until early June and storing most of what we did produce to be sold in June. This will be discussed further later in the call.

Before I turn it back to Tim, I would like to highlight a few additional items. With the second quarter of 2020, we have now recorded 3 consecutive quarters of positive post-CapEx cash flow. We intend to use cash flows to continue to reduce the debt under our credit facility.

Regarding our credit facility, during our spring redetermination, our borrowing base was reduced to $375 million. We reduced our borrowings under the credit facility to $375 million. We initiated the process yesterday to reduce that by an additional $3 million from cash flows, which will bring our amount drawn on the credit facility to $372 million. We drew down $21.5 million in April for our accounts payable discount program. But since that time, with this $3 million payment, we will have paid $16 million down on our credit facility.

We are receiving today another $3 million related to the divestiture of the Delaware assets, which we will be using to reduce the debt by another $3 million, bringing our outstanding balance down to $369 million. The status of the Delaware asset divestiture will be covered more in-depth later in the call.

In addition to reducing our outstanding debt under the credit facility, we have also reduced our accounts payable. Our accounts payable balance at year-end was $54.6 million. That has now been reduced to $19.2 million at the end of the second quarter. We also had cash on hand at June 30 of $17.2 million.

With that, I will turn it back to Tim.

All right, Randy. Thank you for that overview. I'm going to turn this over to Kelly and ask Kelly just to give us an update on how things are going out for the Delaware and just generally. Kelly?

Thanks, Tim. Appreciate it. Thanks, everyone, for joining the call. In a minute, I'd like to turn the call over to Danny Wilson, our Executive VP of Operations; and Hollie Lamb, our Vice President of Engineering.

They are going to walk you through operational events of the quarter and our current activity. But before I do, I want to bring our listeners up-to-date on the status of the Delaware, of course. First and foremost, I want everyone to hear me when I say we are selling the Delaware. That's what's happening. And -- but if we didn't, it's not life or death. I know some of you -- to some of you, it might seem so, but that's not the case.

Our buyer has multiple groups expressing desires to fund them in this acquisition. We've had a lot of conversation with our buyer. Buyer continues to work forward and spend money. And the buyer recently released -- to prove that to us, the buyer recently released $1.5 million to us and now have asked for an additional time in order to make the best possible deal with these financial entities that they're getting expressed desires to fund with.

Also with that, they've recently asked for an additional extension with us, which we have agreed to grant, and they've wired us an additional $3 million for this extension. This is a 60-day extension. And we now have $4.5 million of nonrefundable money. This is not an escrow. This is in our bank account. And the buyer is continuing to spend money, and they're continuing to move the ball forward. That's what we're excited to hear and excited to see.

I'm proud of the job that my team has done during this process and the collaborative effort that the Board has put out in working with us and allowing us the flexibility to get a deal done during very difficult times.

Just to give you some idea from the public record that we can see. I think this is all inverse data. But when you look out in 2018, you could see what looks like 368 deals that we could see that were done; and in 2019, 250. This year-to-date, 47, 47. These are very difficult times. That's why I say I'm really proud to be with the group that I'm with, both the Board and the management and the experience and the amount of collaborative effort they've given to us.

So with that, I'm going to turn this over to Danny to Hollie, and -- so they can give you an update on operations for the second quarter. Danny?

All right. Thank you, Kelly. As mentioned in our operations update in July, activity in Q2 was limited due to the dramatic drop in commodity prices, and in particular, the oil prices. As we mentioned in that release, we had no drilling activity in the quarter. And due to these dramatic drops in prices, we took the unprecedented step of shutting in almost all of our production beginning in the last week of April. Prior to shutdown, we prepped or pickled all of our key wells to limit issues when we decided to go back and restart the wells.

In May, we limited production to just enough to hold the leases with almost no sales, as Randy mentioned. During this time, we constantly were monitoring the prices and the differentials, and as these improved during the month of June, we began to start production back up the first week of the month. And most production was back online by the end of that month.

Because of the prep work in April and May, there were very few operational issues with the restart. Due to the lower activity, our CapEx spend was only $1.8 million for the quarter versus our original plan to spend between $3 million and $3.5 million. For the quarter, we completed 4 ESP to Rod conversions, and this program continues to yield very impressive results for us. Our failure rate on our wells has been cut in half from early last year and has allowed us to also dramatically and drastically cut our CapEx spend.

Prior to beginning the Rod conversion program, our average workover cost on a well was approximately $200,000. Currently, over half of our well work is now around $30,000 or less. To date, we have converted nearly half of our horizontal wells on the Central Basin Platform in the Northwest Shelf to Rods, and we plan to continue to work as we reach the crossover point where Rod pumps become the optimal production method, which, in turn, will also allow us to continue to lower our CapEx spend over time.

Current production continues to run at about 9,000 BOE per day. And with the lower production in Q2 and no planned drilling activity through the end of the year, we anticipate that we will see an approximately 20% drop in year-over-year production from 2019 to 2020.

And with that, I'm going to turn it over to Hollie Lamb, our Vice President of Engineering.

Thank you, Danny. We've continued to focus on reduction in CapEx, while maintaining our positive cash flow. As Danny mentioned, we currently have spent $1.8 million in capital expenditures in the second quarter and $17.9 million for the first 6 months of this year. Approximately $16 million of it was spent in Q1. In Q1, we drilled 4 horizontal wells. We completed 2 additional wells. And overall, we've converted 13 wells to Rods, as Danny said, because the economics are so advantageous. The Northwest Shelf has continued to exceed our expectations, and we're very excited to get back to drilling.

Our CapEx plans for H2 of 2020 are minimal based on the current economic environment, but they're subject to change. As previously stated on our calls, a stabilized price in the mid-40 per BOE would signal a return to drilling. And it's still the case. As Randy has mentioned, our average oil differential is approximately $2.50. So the market's not there yet, but it's moving in the right direction, and we're excited about what the outlook looks like.

Our internal rate of return at the mid-40s range is from the mid-60s to upper 70s to low 80s depending on area. We have modeled a 16- to 18-well drilling and completion program within cash flow at these prices.

At -- with this, I'll turn it over to David.

Thank you, Hollie. Appreciate that report. As Kelly mentioned earlier, M&A activity has underperformed in 2020, primarily due to the pandemic and the flooding of the oil markets by OPEC Plus. And further M&A activity has probably been pushed to either the second half of this year, but more likely that'll probably take place more in 2021. And until we see a vaccine approved, we get past elections and see an increased consumer confidence that increases demand that puts a significant dent in the large global inventory overhang, it's going to continue to cause valuations and consolidation talks to remain strained.

Additionally, in the second quarter, we elected not to renew a block of acreage that was predominantly located in Northern Gaines County. The acreage was not a focus area since it would would've required a large upfront CapEx investment to construct the SWD facilities, electrical and oil and gas infrastructure to accommodate a development program to a level we already have in place on our Southern Central Basin platform acreage as well as our recently acquired Northwest Shelf assets in Yoakum County. With the addition of the Shelf acreage and just as a reminder, that's 48,000 gross acres and 36,000 net acres, we now have a high-quality inventory of over 340 Tier 1 and Tier 2 locations that gives us over a 15-year drilling inventory.

Now that we have these top-tier locations in hand, it was determined that extending these mostly Tier 4 locations. Now Tier 4 meaning unexplored or underexplored, but basically a higher element of risk, just wasn't a good use of capital in our current price environment versus the notable economic impact we would see from the growth, improved reserves and increase in EBITDA if we use the same dollars to drill the high rate of return horizontal wells on the Shelf. And in case you're wondering, there's no proved reserve -- there were no proved reserves allocated to this acreage. So it will not in any way affect our stated and published reserve numbers.

And with that, I'll turn it back to Tim.

All right. Thank you, David, and thank you, everyone. So this concludes the company's portion of the 2020 second quarter and six month review.

I'm going to turn it back over to the operator and ask Diego to open it up to our listeners for any questions that we may have. Diego?

(Operator Instructions) Our first question comes from Neal Dingmann with Truist Securities.

Kelly, my question for you or Danny, when you guys decided to come back, price is certainly rising nice. Could you give us an idea of kind of regionally, will it be up in the Shelf that you're still targeting? And if so, kind of, what that plan may look like?

Danny, go ahead.

Yes, Neal, that's a great question. It'll be a mix of both areas, but the predominantly, it will be in the Northwest Shelf. We do have some drilling commitments with the University Lands asset that we bought from Tessara prior to the Wishbone acquisition. But the bulk of the activity will be on the Northwest Shelf.

Very good. And then just 1 last follow-up. Just on hedging, you guys were very successful this year. Your thoughts in oil still, kind of, low 40s, Kelly how you feel about it or Randy or just, Tim, in general, just the team, kind of, on a go-forward basis as you get into '21?

Yes. Well, Neal, that's a good question. And as you know, we do have hedges in place for '21 now. Randy probably has the exact number in front of him, but my recollection is that we're probably somewhere in the low to mid-40s, locked in on about, I believe, 4,000, maybe 4,500 barrels a day. To that extent or with that said, I can tell you that as we continue to see the improvement in the commodity space, we are certainly open to add more hedges as time goes on. But for now, we think we're well positioned for the rest of this year. As you know, we're locked in at $50 on 5,500 barrels. And then as we go into '21, as I just explained. But we will be looking to add to that component as we near 2021.

And it is 4,500 barrels a day with an average floor of 4,222.

Yes. Thank you, Randy.

Our next question comes from Dun McIntosh with Johnson Rice & Company.

My first question was on the trajectory over the second half of the year. In your prerelease, you talked about production being down about 20% year-over-year. Could you provide some clarity if that's kind of exit to exit or full year versus full year? And kind of what -- you said you're up at 9,000 today, kind of just where you kind of think third quarter, it might be too early for guidance on volumes, but kind of third quarter going into fourth quarter and how you're, kind of, positioned to start '21?

Yes. Dun, this is Danny. That number I gave you of 20% is a year-over-year number, not the exit rates necessarily. I think for this quarter, we're looking at something around that 8,900 to 9,000 BOE per day is probably going to be a good number for us. And then second -- or third, fourth quarter might be slightly less than that.

Okay. And then, David, maybe just a little clarity. You talked about the closing of -- I assume you're talking about the Delaware sale and whether it's second half '20 or -- but into '21, you mentioned you deferred 60 days, but when you're talking about early '21, are you talking about additional asset sales there?

Kelly, do you want to go and take that since you've been on the front there.

Yes. Dun, the 60-day extension is in respect to the Delaware, of course. And I think David was just referencing the market in general. We're seeing a lot of deals. David sees things and hears things all the time. We're getting our door knocked on a lot by a lot of different people. As a matter of fact, during this process, with us talking to this particular buyer or the prospect, we've been turning down calls, even some calls that have come to our General Counsel, others have come to land people in the company. And so we've had to tell people, look, we're locked in here. We've got a group that's pursuing this, and they're spending money, doing a good job, and they're going to get it closed. And at the end of the day, there's just a larger number of people have started to line up for us. And that's been interesting to us and exciting.

But at the same time, David, I think, was just mostly referencing the market in general as to how he sees, how things might -- how the acquisition market might pick up or might not.

(Operator Instructions) Our next question comes from John White with ROTH.

On the impairments, could you provide an approximate breakdown by area?

Randy, can you respond to that, please?

It's not really calculated by area. As a full cost accounting company, the full pool is considered against the value of the reserves. So there's not really any practical way to break it out.

Understood. And on CapEx, Hollie was clear, you would start drilling new wells if you saw sustained prices in the mid-40s. Let's say, what would you say for the remainder of this year if prices stayed above $40 but below $45, what kind of CapEx in the third and fourth quarters could we expect?

Yes. So let's kind of look at it this way, John. This is Tim. Let's look at that with a drilling -- a potential drilling program that could fit in between now and year-end and the absence of that. In the absence of that, I think Danny and Hollie both touched on that, and I'll ask them here in a moment just to review that again. But if just -- the question, if prices were to stabilize or sustain here, and we felt comfortable that we were going to realize, and that's a realized price of -- in that $42 plus or minus range, if we really thought that we were going to have a solid look at that as we look down between now and year-end, we could accelerate our thoughts on drilling. Right now, our thoughts are that we're hoping that by year-end, we're continuing to see what we're seeing now and some even more improvement. And what Hollie made reference to and what she touched on, we could be -- we've modeled out 16, 18, we even modeled out 20 wells that we could drill with a realized price in that $42 plus or minus range and do that within cash flow and yield something north of 60%, depending on platform, 60% to as high as 70% plus internal rate of return on the Northwest Shelf.

Danny, Hollie, did you want to just -- for John's question, maybe just review again, those CapEx expenditures in the absence of any drilling.

Right. No. And I want to point out that, that is on a -- when Tim is talking about that $42.5 range, that is a BOE basis. So that means oil is going to have to be up in the -- probably mid- to -- no, not up to $50, but somewhere between $45 and $50 when you take into account differential and then the dilution that's caused by the lower gas prices. So that's kind of the range we would need to be in. In the absence of that, we're still sticking with our plan to have our CapEx spend of $25 million to $27 million for the year when we spent approximately $18 million of that so far. So you can figure out kind of where the remainder is going to be.

Our next question comes from Noel Parks with Coker & Palmer.

You're certainly in good shape with inventory, but I was wondering, are you particularly active with leasing on the platform or to the degree you're doing anything? Is it just on the Eastern Shelf?

David, do you want to address that?

Sure. I'd be glad to. Noel, good to hear from you this morning. No, right now, we're -- the acreage that we like, of course, we're renewing as it comes up for expiration. But for the most part, there's not any new leasing activity going on. And we're just focused on maintaining the acreage that we want to keep that shows a lot of good promise for development potential going into next year and beyond.

Okay. Great. And along the lines of other questions you've had about at this price level or better? What would you do? I'm just thinking, what's kind of the cheapest way you can position yourself, cheapest or maybe I should say, most cost effectively to sort of take best advantage of a rebound in oil down the road? I mean, I'm sort of thinking at the mundane end just like permitting, but what more can you do? It sounds like you've already got the 16, 18 and even 20 wells identified for what might happen next. But anything else in terms of prep work you can do that's, again, not too expensive?

Yes, that's a great question, Danny and Hollie, maybe you could address that for Noel.

Absolutely. So we have approximately 30 permits waiting to be drilled. Those are surveyed. We know we have infrastructure in those areas to minimize long-term CapEx issues. And so we're kind of prepped and ready and just waiting for that gun to go off, and we're going to be sprinting across the finish line.

Great. Okay. I'm sorry, was there anything else about Tim said somebody else might answer.

Yes. I just mentioned, Danny and Hollie. You may be referencing that. But I think she gave a pretty good response.

Great, great. Okay. I just wanted -- I didn't want to jump back in. And I think that's -- I mean, do you have any thoughts or expectations? Or what do you think you're modeling as far as what differentials might look like heading into the rest of the year and next year? Do you think the worst of the volatility we've seen is behind us? Or do you think there's still some risk there as we maybe -- as the industry kind of goes through maybe, kind of, a lumpy process of gradually getting, I guess, the rest of the shut-in production online but also maybe heading towards drilling again?

Yes, yes. Danny, I know, watches that on a daily basis. So Danny, maybe you can comment on that.

Yes. Noel, that's a good question. Really, all I can do is look at the futures as we look forward. And right now, the differentials seem to be very, very steady as you look out into the future. Particularly, we have 2 main differentials that we deal with, and that's the CMA roll, and then the other is the WTI, WTS differential. Saw some information last week, I mean, the different -- WTI, WTS differential is basically expected to be 0 in the foreseeable future. As long as the commodity prices, as long as we don't see a huge jump up or down in these or just a gradual improvement, the CMA roll which is the other component is very, very minimal compared to some that we saw, obviously, back -- especially back in April. So I don't expect to see a lot of big swings one way or the other in those. So I think we're looking at some fairly stable pricing at least differential-wise between now and the end of the year, going into next year.

Oh, great. And I guess just wanted to touch back on the extension you gave the buyers of the Delaware Basin asset. I was just curious, had -- did they approach the transaction initially with the assumption that there was going to be a particular funding source? And has that really expanded a lot as far as the folks looking to participate since then? Or is that more a process of they thought they were going to go one way. They decided they needed to make a change, and so now they're, kind of, in this different process of nailing down their sources?

Yes. Good question, Noel. Kelly, why don't you clear that up for him.

Yes, yes. Noel, they had a number of people come at them. And people are very creative nowadays, and a lot of these funding sources are realizing they're having to get creative as well in order to get deals done. And so this group is fortunate enough to have a number of people come with them. And as you're moving towards a closing, if I were in their shoes, I'm speculating somewhat here, they're seeing and hearing ideas that might make more sense. And as a result of that, it gives them the opportunity and flexibility if they're willing to put up risk, and they were. I mean one of the key points that I'd referenced, I want to be sure everybody heard is that we have $4.5 million that's nonrefundable. I still own the assets. And at the end of the day, these guys are not just giving me $4.5 million, they're spending money. I mean, they're signing additional deals that could help the saltwater disposal system, which if you remember, a lot of that's commercially permitted. So they're going to take some outside water. I mean they're doing all kinds of things that are costing them money and moving them towards the deal.

And like I say, not only have they had creative resources coming at them from a financing standpoint, we have a number of people surface on our side, probably 5 or 6 that have said, hey, these are viable people. These are real people saying, if this deal doesn't close, we want it. But the bottom line is it's closing, and we're selling it, and these guys are coming at us pretty hard, and they're proving that by just stepping up to the plate, just like lining us additional nonrefundable $3 million. I think that's about as good as you could hope for.

Okay. Great. And just to the degree you can comment on it. So then is it safe to assume that the principals, the folks that are looking to do the deal you've negotiated with. They're basically operating folks, and they're sort of bringing in financing, they're not like private money or a fund or anything that has like an operating team in the wings or anything?

No. These are guys that have been in the business a long time. We know of several of them involved, some of them have been around the business for 30 years. And so they've been operators in the past and operate properties now.

Oh, okay. Great. That's helpful to, kind of, get some context for how it's all unfolding.

Sure.

Our next question comes from Logan Moncrief with Thomist Capital.

The next question comes from John White with ROTH.

Just wanted to follow up. Kelly, you mentioned you had received $4.5 million from the seller -- the buyer of the Delaware asset? Is that the total amount that you've received?

Yes, that's what we've received so far. So they originally put up $1.5 million in escrow and then released the escrow to us and then turned around and came at us with an idea that if we could help them with an extension in order for them to make a better transaction based on all the things that were happening in their camp and then were willing to put up $3 million more, again, nonrefundable, wired directly to us. That made a lot of sense. So yes, that's what we have, $4.5 million.

That will save going back through press releases. And just to clarify once again, your previous question you commented the buyer is actually doing work on the Delaware Basin asset.

Well, they're not working on our Delaware Basin asset, of course, because they haven't closed on it yet. But they have been out there a number of times. I can say that through the due diligence process. They know the property almost as well as we do at this point. And when I say work, I mean, to do -- to take third-party water, you're going to need to move the ball along by taking leases, putting out deposits, things like that, making contractual arrangements with other parties other than us. And what I see happening out there with them is they're making arrangements, they're moving. They're spending money over and above what they've given us. They're spending money also in anticipation of getting that closed as quickly as possible. And listen, although we've said it's a 60-day extension, that doesn't mean they'll take 60 days. I mean, they could close at any time in between now and then. That's just what they asked for.

All right. I appreciate that. So the work they're doing on, say, offset acreage?

Yes. They're putting themselves in a position to be able to take advantage of not just to the oil and gas assets where possible pursuant to however they want to do that once they acquire it, but it's also the water assets. These are very experienced operators. They're also very experienced operators in the saltwater disposal business.

My understanding from some other sources was that they are primarily a water company, not an E&P company.

I think if you're looking at just 1 or 2 names, they have several entities that are out there. So I'm not sure what sources you're looking at. But at the end of the day, these are previous operators. These are guys that have operated fields that I'm familiar with, some of them are substantial. And they have partners with them as part of their organization that are also currently oil and gas operators.

Okay. I'm sorry to keep coming at you, but...

That's all right.

So does your previous comment suggest there's multiple buyers?

No, we have 1 buyer.

Okay. And just one more. Are they looking at that traditional bank financing? Or are they looking at nonbank financing?

I don't have the answer to that. I mean I know that they've had several people that they have worked with in the past, are currently working with, but I haven't gotten into the weeds as to the specifics associated with which group they're going to go with or which group is funding them at this point in time.

Our next question comes from Logan Moncrief with Thomist Capital.

A couple of questions. First, on the 9,000 barrels a day of current production, does that number include the roughly 900 barrels a day to be divested?

And then second question around the credit facility. How much of the capacity -- current capacity on the credit facility is tied to the divestiture? In other words, is -- would there be an expectation that the credit facility might come down a little bit, solely based on the reserves that are divested with that Delaware deal.

Yes. Logan, this is Tim. I'll take the latter part of that question. It is. So when that ultimately closes -- the sale of Delaware ultimately closes, we will be reducing the facility by a minimum of $20 million, and that will reduce the base from the $375 million to the $355 million. As explained earlier in the call, we now, as of today, we will be instructing to wire an additional $3 million that's on top of what was paid or was instructed yesterday. So our outstanding balance as of this next wire will be down to 2 -- excuse me, $369 million. So that $369 million will be the outstanding on the $375 million base. Delaware closes, the base will go down to $355 million, but the further reduction or an additional reduction of another $20 million will come along with that.

Danny, maybe, could address the other part of that question.

Yes, Tim, and Logan, the -- currently, we have not been spending any money out on the Delaware in anticipation of this because there was a point in there where we were no longer spending our money, but we were spending the buyers money. And so we've held off on quite a few of the workovers that needed to be done out there. So currently, that production accounts for about 6% of the total. So upon closing, we'll drop about 6% overall. And so it's not a substantial hit to us. But there will be, I'm sure, and as Tim mentioned, there will be some value associated with the Delaware that will come off of the line.

Logan, Danny's referenced on spending the buyers' money, of course, if you didn't know, you may know that is the effective date?

Yes. And the effective date, is it still end of Q2 or is it end of Q1? What is the assumed effective date?

It's August 1.

August 1. Okay. And so like when we're looking at -- you mentioned that production in Q4, just kind of giving some color, you said kind of expect 8,900 to, 9,000 here in Q3 and then Q4 slightly below that. That is that's kind of like -- is that a preacquisition number, so kind of adjust that but -- those numbers by about 6%. Is that a good assumption just for our models?

Yes. Logan, that is correct.

There are no further questions at this time. I'll turn it back to management for closing remarks.

Okay. Thank you, Diego. We want to thank everybody for joining us today. We know that it's a busy time. And as in the past, we also want everyone to know that our doors are open. So if you have follow-up calls, you know that Bill Parsons in investor relations is available. And if we need to set up calls with management, we can do that as well. So have a good day, and appreciate your support.

Thank you. This concludes today's conference. All parties may disconnect. Have a good day.