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Greetings, and welcome to the Diversified Gas & Oil PLC Acquisition Update Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Chief Executive Officer, Rusty Hutson, Jr. Thank you. You may begin.
Thank you. Appreciate everybody's time this morning. As most of you know, we put out an announcement this morning that we have acquired some assets in Louisiana, and I want to go through a presentation that each of you should have had that was on the -- with the announcement to just really talk a little bit about the decision of the area that we're entering, to talk about how it fits with our model and really the future as it relates to being able to continue to acquire and to add additional assets in this area. I'm going to flip through and I'm going to reference pages. It's a small presentation, but I'll flip through and reference the page that we're -- that I'm talking from. Right now, we start at Page 3 of that presentation. Really just wanted to give a real quick emphasis on what the business model has been. We've obviously been very successful in Appalachia, in rolling up assets, adding people along with those assets as we do so, that have been the backbone of the company and being able to operate not only the wells in enhanced production, but to be very efficient in the operations. And as we've added assets there, we've grown it. The economies of scale have started to show through in the numbers, obviously, over the last 4 years. And then we've obviously put a lot of processes, a lot of technology in place and systems. And it's really created a very strong foundation to sustain and expand our asset portfolio as we move forward. And so you can see here, we started $75 million 4.5 years ago. As we sit here today, close to $2 billion in enterprise value, $1.1 billion, $1.2 billion in market cap, and we've done that through the strategy that we set out from day 1. You can see at the bottom of that slide at the time that we went public back in 2017, the company was $4 million in EBITDA. Today, we sit here at over $300 million of EBITDA, and that's prior to this acquisition. And we've scaled it up. The model is working. The ability to add assets and drive economies of scale, increase production on wells that other folks have not paid as much attention to has really worked, has created value for the -- for our shareholders, has allowed us to free cash flow the business at a high margin and pay dividends, as we said we would. So the consolidation strategy really has set the stage for where we're going this morning with our announcement. If you flip to Page 4, the executive summary of this deal. Why this area, why this regional area of the country versus something else? And we've really investigated and done a lot of due diligence on areas outside of Appalachia. I spent a lot of time looking at assets in other areas and trying to come up with what's the best area to replicate what we've done in Appalachia. We believe this area, and you can see here on this map, the green area that's kind of highlighted, really gives us access to assets that really fit the characteristic of what we've done within Appalachia. Compelling valuations, a lot of ability to scale up, a lot of segmented and disjointed production. What I mean by that is a lot of different operators hold that [ whole ] production. And so it gives us the ability to roll up a lot of different operators. There's not just 1 big player that we have to deal with in those areas. I think it gives us a conventional style of production in the middle of a large shale play. And so a lot of the operators have moved on to a shale. In this case, the Haynesville Shale in this area, and have really abandoned, to some degree, the operations of Cotton Valley. They're not really focused on it, similar to what we saw in Appalachia. The Marcellus and Utica took over, and conventional Appalachia was kind of a forgotten asset. And we believe those are the kind of assets for our business strategy, gives us the highest potential for success. And so we think this area is a really, really high return area for us to focus on. The transaction overview, we obviously paid $135 million gross purchase price, net of purchase -- an estimate. But net of purchase price adjustments, around $115 million of cash out the door. The effective date, and that's the reason for some of the purchase price adjustment, is March 1. We expect to close it in the month of May, middle to late May. Financing on this, we're using our RBL to -- we have ample liquidity to acquire these assets without any type of additional funding sources. We may look at some type of ABS structure on the back end of this, but at this present time, it's an RBL deal. The purchase price multiple is very, very compelling, 2.9x. We're picking up around 16,000 BOE per day, obviously, in natural gas asset. The 16,000 BOE per day puts us at 120,000-or-so BOE per day as a company. And the PV10 was about $175 million. So we estimate this is probably around a PV17 or in that arena on just PDP only. Much smaller well counts. And one of the areas that we really like about this -- the Cotton Valley is that you get a lot more production with a lot fewer wells. So about 800 approximate wells, 780 of them are operated. So those are the ones where all the value is. The average well or the [ advantage ] on these wells is around 17 years. So that's a decent starting point for us. The first year decline is around 14%. That will continue to moderate down as we move over the next few years into those single digits, which is where we want to be. Acreage about 180,000 acres. The beauty of this area and what I really like about it is the fact that netback pricing, so our net pricing after basis dips is at a much higher net back than what we've been seeing in Appalachia. The average basis differential here with Gulf Coast type pricing is around $0.10 to $0.20 negative versus $0.50 to $0.60 negative on average in Appalachia. The first year adjusted EBITDA around $40 million, which, as we said, is a 2.9 multiple. The estimated cash operating cost, $1.36 per Mcf equivalency. But it will still represent a very high margin because of the net pricing that we see in this region. So 50% plus margin. That's a great starting point for us. We look at that and say, listen, if we're buying an asset with a 50% margin already, how much higher can we take it when we start to really scale up the region. So that's kind of the overview of the assets in general. You can see the math that we put over there. The green area that we really call our new focus area being Northern and East Texas, Northern Louisiana, Oklahoma and the western side of Arkansas. So that's really the -- what we're calling our new Central Region Focus Area (sic) [ Regional Focus Area ]. Page 5, what makes this area so attractive as we kind of hit on it on the last slide. But you can -- I think something that's really telling here is if you look down in the left-hand corner, and you look at all the wells that have been drilled in the Cotton Valley over the years. You can see here a majority of the wells have been drilled prior to 2008. So a significant number of those wells were drilled in 2008 and back, which tells me there's a lot of mature production that can be acquired in this region. Not a significant amount of development in the last 5 to 7 years. And so that's where we like to be. We like to be where the production is more mature, a little easier to predict, to hedge out and to lock in those margins that we talk about. A lot of assets here for sale, a lot of ample opportunities and potential to acquire and to drive the scale that we did like we did in Appalachia. We're -- we believe there's a lot of opportunity to go in because what we're seeing on the Cotton Valley is the same thing we've seen in Appalachia from the standpoint that the operations of the Cotton Valley wells have been kind of just kind of forgotten. Everybody is focused on the drill bit in the Haynesville and they're not really focused as much on the Cotton Valley operations, and that's really where we can drive value. The differential pricing we talked about, it's in close proximity to the Gulf of Mexico, it has the LNG markets that -- for exports that are really close. So it keeps those basis differentials in a very low area. Extensive takeaway capacity here. We have lots of pipelines. We'll see a picture on the next page, I believe, but we have a lot of different options as it relates to takeaway capacity, not any kind of issues in terms of being able to move and sell the gas. It's a significant gas-weighted area, which is good. It has a lot of infrastructure, has a lot of compression, it has a lot of NGL facilities in terms of extraction. So all that stuff that we need to be successful in this area. And the other beautiful thing about where we're entering here is a very, very favorable state regulatory area in terms of just being able to operate. They're very energy focused, both in Louisiana and Texas, and it's not -- it's not a political issue in these 2 states. It's definitely an area where they welcome the operations of oil and gas. On Page 6, this kind of goes to the takeaway and the favorable basis differentials that we're seeing. You can see there's a lot of pipelines here. A lot of them move gas to the Gulf Coast where you have -- especially the Houston Ship Channel, which is where this gas that we'll be operating is based on great differentials. You can see, on the 2 pictures on the right, how that plays out. And you can see that, for the most part, very stable. Houston Ship Channel has been very stable to flat, close to flat and to Henry Hub to being favorable to Henry Hub at times. And so it's a very stable pricing environment. On Page 7, kind of a comparison. I like this slide because it kind of shows how we feel this thing frames up compared to where we're at already in Appalachia. And you can see primary products being natural gas, obviously. Basin maturity as it relates to the Cotton Valley alone, not the Haynesville, but Cotton Valley. The decline profiles are very, very similar. A terminal decline rate in the single digits is a very good place for us to be. And you can see kind of how we frame it up on the right and illustrative type wells and where we like to own it, when we like to acquire these assets and in that more stable production decline. You can see the terminal declines are very, very similar, 5% to 6%. Primary well fluid control is artificial lift. We're very, very confident in that area. Our well operators in Appalachia and our supervisors and such, all are very confident with artificial lift. So it's not something that's new to us. We understand how to do it. The depth of the wells are a little deeper here, but the complexity of them or not. And that's -- the one thing that we don't like to do is have to go in and deal with complexity in the wells and high-cost operations and high-cost workovers and those kind of things. These are very similar in the way that you operate these as you do in Appalachia. The retirement cost for the deep wells of $80,000 to $90,000 a piece compared to our Marcellus wells in Appalachia, which are in that same type of depth of $75,000 to $80,000. The beauty here is that you have much fewer wells. And so the average remaining life on these are 50-plus years. We're 17 years on average in. So we're in a very good position to continue to operate the wells in an economic fashion and not really have near-term asset retirement obligations that we have to deal with. On Page 8, we talked about the favorable operating environment. We really had had, through our due diligence process and being with the employees and that we're picking up in this deal, which is very, very important, as you guys know, retaining the knowledge of the employees that are on the ground already has been paramount in our success in Appalachia, and this will continue here. And so we're picking up 25 employees that are very familiar with these assets, understand the operating environment, understand the pipelines and how we move gas. And so that's a very, very important factor. This is like -- this transaction is like Brad, our operating -- Chief Operating Officer said, we're sticking our flag in the ground. This is it right here. And I believe that it's going to pay and we'll start to see a lot more opportunities to continue to add here. Favorable operating environment. We talked about the regulatory environment and the social environment there. People love oil and gas in these states. It's a big employer. Its big royalty owners love it. I mean it's just thought of in a different way than some of the Northeastern states that we currently operate in. Value drivers of the asset. It's held by production, all the leased acreage, 180,000. The thing I would tell you about the Cotton Valley is, the returns on new wells in the Cotton Valley are not what you see on Haynesville, but they're still really good. And so even though that nobody is -- most people have turned away from the drill bit in the Cotton Valley, to the Haynesville, that doesn't mean that there's not some pretty economic wells that you could drill in the Cotton Valley if you deemed to need to. But -- so there could be some other ways for us to extract value out of this deal, do farm-outs or whatever. But -- so there's always that opportunity. We've already hedged this, or a significant portion of it. We've got 80% of the production primarily through 2 different ways we -- we're going to novate some of their hedges, and we also put some of our own on for the 2021 production. And then we have about 50% of 2022 already hedged on this transaction. We talked about the terminal declines and the low decline profile of these assets. Very good strong cash flow generation in these -- in the operations here. Geographic density. We love the fact that the Cotton Valley is pretty concentrated in terms of the geographical area that we're dealing with. So as we continue to add additional assets, the scalability and the synergies will be -- will become more and more apparent. Good extensive network of third-party gathering and midstream assets gives us a lot of optionality, but definitely some really, really good pricing, which then obviously result in very good margins of 50-plus percent margins in this area before we've been do anything with it. You can see on Page 9 the accretive value of the transaction based on 2020's EBITDA. This would add about 13% of accretion. On the EBITDA basis, the daily production going up, the PDP reserves all going up. We love it. We think this is a great start for us in a very good area. You can see the net wells by age. And the beauty of our portfolio now is we still hold a majority of our production in conventional style assets, both in Appalachia and now in Louisiana. And so those are the backbone of the company. And they really -- they provide stability, a very predictable production profile, which, again, gives us the ability to hedge and drive cash margins. And so that's the important part of this. And you can see over on the side, where our hedges are on this transaction. We're evaluating some additional protection on this, but we see some opportunities to do that on the back end of the transaction later this month. But you can see we've blocked in $2.79 for '21, $2.79 in '22. I guess we do have a little bit in '23 there at $2.67. So all in all, very, very favorable metrics behind the deal. And then on Page 10, I'll just say real quickly, and then we'll allow you guys to ask some questions. This is a very -- this is going to be an area that we're focused on. We will continue to -- you will continue to see deals here. And I would venture to say that you'll continue to see deals here in the not-so-distant future. We have the ability, we've got a good foothold here now, we've had discussions. People know us in the region. We've had discussions with other private equity-backed companies, we've had discussions with other operators there. We believe we'll have opportunities to continue to add scale and size here in a very short period of time. And you can see all the key benefits of this acquisition and how it's going to impact our model. We just -- we feel like that we're entering an area now that could easily, in a short period of time, in a year or 2, surpass the size of what we've eclipsed in Appalachia. And so with that, I will -- I'll stop. I think you guys can see that we're very excited about this. We feel like that it's going to -- it's going to be very accretive to our shareholders today, but it's going to add -- give us a lot of opportunity to add a lot of value on a going-forward basis as we continue to add in this area. So with that, I will stop. I will allow you guys to ask any questions. So moderator, if you don't mind, you can open up the question line.
[Operator Instructions] Our first questions come from the line of Alex Smith with Investec.
And I guess my question is, the first part you previously alluded, it would look at new regions. And I guess my question is why the move as opposed to centralizing Appalachia? Are we talking of the fact that in Appalachia, there is a lack of opportunities? Or there's more competition packages? Or are we seeing higher prices in Appalachia? I guess other competitors have announced their intentions to consolidate in the region. And is this the dynamic what you're seeing and kind of why you're shifting across to a newer region?
Yes. Alex, we don't -- Appalachia in is still always going to be of interest and a primary focus set for us. Conventional wise, there are still some bigger -- a couple of different packages there that we obviously have our eyes on and we'll continue to watch and monitor. The shale is always going to be there. We're going to continue to see more and more of those assets come to market and people looking to divest and to monetize. The one thing that we saw here was our ability to do what we did in Appalachia, but also to get a better price for our gas. What we're seeing in Appalachia has been pretty consistent, is a negative $0.50 to $0.60 basis differential. We saw this area, we see the assets that are available for sale or will be available for sale, potentially, and the ability to scale it up at a much higher natural -- netback natural gas price, which is important. And so we just -- we don't really see it as we're moving out of Appalachia and moving to another region without really focusing on Appalachia. There will continue to be opportunities to bolt on in Appalachia. And we'll continue to look at those and monitor those. But we just see this as a very compelling opportunity valuation-wise. Listen, if I'm looking at Appalachia and I'm looking at Cotton Valley, and I see an Appalachian asset that's at a PV13, 14, 4x multiple, but I'm looking at Cotton Valley assets with similar dynamics, but they're a 2.9 and PV18. But the -- it's an easy decision. It's all about value, and it's all about where do we get the most long-term value for our shareholders. And I believe that Appalachia will continue to give us those opportunities. But I think going into this region, is a -- there's just going to be a lot -- it's going to be like when we went in Appalachia. We're going to see a lot more opportunities to do this in a shorter period of time, but Appalachia will continue to be bolt-on type situations there also.
[Operator Instructions] Our next questions come from the line of Chris Wheaton with Stifel.
A couple of questions from me. As we saw Appalachia grow and your strategy rollout, midstream became quite important. Midstream assets became one of the things you were hunting for. Can we see -- should we expect to see that here in Cotton Valley that you do need to get infrastructure as part of the part the strategy of growing out the wells and growing out your footprint in the region? And particularly if -- or is it that some infrastructure doesn't matter as much because you've not got sort of some of the potential takeaway constraints you've seen in Appalachia starting to bite on differentials? You've got much less of an issue in in the Cotton Valley. I'm just interested in that question. Secondly, are there potential synergies between the 2 geographic areas, particularly in areas, for example, like trading of gas, being able to swap gas supplies from one part of the country to another. Is that potential upside for you longer term? And that's my second question.
Yes. Those are great questions. I would say, initially, our focus will not be on midstream assets in the Cotton Valley or Haynesville or whatever you want to call it. It was integral to do that in Appalachia because of, as you know, the capacities in certain pipelines, the ability to move gas to better markets and to find ways to increase your netback pricing in Appalachia. It's just -- it's an area that's got a lot of strain to gas right now in terms of the Marcellus. And the Northeast is not using as much of it, so that's why we're seeing the base differential we're seeing. But I don't see that here. The export LNG facilities that are on the Gulf Coast, I think they utilize a lot of the excess gas down there. And so it's not as important for us to have midstream assets there at this current time. Now that's not to say at some point, once the operation gets bigger in that area, that we don't see that as an opportunity to do, kind of like we did in Appalachia. But right now, I would say we're focused on production and additional opportunities there. And as we grow it, the potential may be there for midstream assets later. But I would say right now in the near term, that would not be our near-term focus. I didn't hear the second question. What was it?
The second question was about the opportunity to swap gas with marketing operations. Well, that's a -- it's great question.
Yes. No, I think that we're going to have to do some more research down in the Cotton Valley alone. Is that what we're talking about?
Well, just the fact that we're in multiple basins, that we can swap. Where there's...
Yes. There's no doubt that the Northeast right now, if you just look at the Northeast production, a lot of the gas is flowing west. So during the winter month, it flows east, it goes to Northeast, it goes into the Virginia market. When the winter shuts down, a lot of that gas flows back the other way. It goes back toward the Midwest, it goes to the Gulf Coast. And so there's no doubt that, that is a big part of a lot of the Marcellus guys, specifically being able to continue to drill wells, in their words, in an economic condition or factor. I don't think it really is as economic as they say it is. But they're moving it to a better market. So I do believe that, that is a opportunity for us at some point. We've got to -- we -- but most of that is going to entail us buying or acquiring midstream assets in the East, in our Appalachian area, and then getting that gas into pipelines that come to the Gulf Coast. So I think the Gulf Coast is definitely the biggest opportunity we have from Appalachia on getting gas to a better price market. And listen, we have opportunities to do that. We've got a lot of things that we're looking at in terms of pipelines. And those move a lot slower because of the sellers. But we do believe that there's going to be some ways of us getting more gas to better price markets when the price is not as good in Appalachia. I think Cotton Valley is already there. That gas is not stranded. It has plenty of usage and it gets out through LNG exports. If there's no domestic use, it goes through the exports. So I think that's the way I would frame it up at this point.
[Operator Instructions] Our next questions come from the line of Simon Scholes with First Berlin.
I've got 2. Firstly, on Slide 5, I mean you've provided some very interesting information on the number of producing wells in the region. I was just wondering how many of these are actually -- are these producing wells are actually on your doorstep in the Cotton Valley. And then secondly, on costs in Q1. It looks to me as if the unit costs have increased -- in Q1 have increased quite sharply versus last year. I think recurring G&A was $1.73 in Q1 versus $1.33 in last year. And it looks like the total operating expenses on a unit basis before G&A were also up quite substantially adjusted basis $5.98 versus $5.59 last year. So just wondering if you could comment on cost development in Q1.
Yes. Let's talk about the first one, the first thing first, which was the Slide 5. I would say that all of these wells -- so the Cotton Valley is not a significant geographical area. It's mostly East Texas, North Louisiana and that Northwest corner of Louisiana. So pretty much all of this is in that area. I mean, I would say there's probably none of this that would be excluded because of distance. So it's all a very tight geographical area, the Cotton Valley itself, you can kind of see it on that map right above that on Page 5 that the blue type area, that's it right there. All those wells are in that area. Some of them -- some of them have been drilled horizontally in the conventional sand. Most of the newer stuff that has been drilled over the last 10 years relates to that. But we believe this is all an opportunity set for us in this area. So I think -- so it's all there for the pickings at some point. Te bar chart though...
And this central area is quite extensive. I mean it extends up to -- even into Kansas and Northern Oklahoma.
That's correct.
I mean how many of them are in north of Oklahoma City?
Well, Cotton Valley doesn't extend up to that area. Yes. We've circled this whole area. And if you really look at it, I know it looks like it's vast and huge and all that. And it really does -- I mean there's a lot of area there, but it's not that much different than what we've already done in Appalachia. We -- it's an extensive area that we operate in, in Appalachia. And importantly, just as we shaded more darkly the Cotton Valley and Haynesville regions where these assets sit, if we were to shade all of the individual producing basins within that green area, it would provide greater context for why that shading is the way it is. The point is, there are many producing regions here with assets that meet our profile, our entry point, and we chose an entry point that we believe was prudent and give us an opportunity to establish a presence and build an understanding of the area before we continue to leg into more assets. But there are many producing areas outside. And that's -- we just featured the one where the assets sit today, but it's not just an arbitrary shading across. There are several producing regions there. Yes. As it relates to the cost, so what I would tell you is, we were very clear last year about our G&A structure. We needed to beef up our G&A structure for, number one, as we moved up to the premium board and the FTSE 250 company and the additional governance related to that. We brought on PwC, we added directors, diversity on the board, Netherland Sewell as our as our reserve engineer. We had to do a lot of that. We also had to really beef up some degree our financial capabilities and our financial analysis capabilities, our engineering capabilities, measurements, those kind of things. We really wanted to make sure that we were setting the company up as we moved into this next stage of growth. And as it relates to what you see today, the Cotton Valley, and additional opportunities. That we were prepared to do that, backroom operations, all the things that were necessary. We were very clear about that, that we needed to do that, and we have. And so you do see a little bit of an increase in the G&A cost from quarter-to-quarter. The other thing that you see in the first quarter, which is really pretty much every year is in the U.S., certain taxes are reestablished in the first quarter on payroll. And so what happens is you -- those kick back in, in the first quarter that -- and then as soon as you enter the -- or go through the end of the first quarter, a lot of that will roll off again as people maxed out. And so that's a big pop that we see pretty much every year in the first quarter.
Yes. We budget higher in the first than in any other quarter.
Yes. Now as it relates to the other expenses, you can go ahead and talk to him about the operating expense.
Yes. I think if you look across the operating expense, the one that we really focus on is we talk a lot about base LOE because that's the piece of the cost structure that we directly control with our employees, our Smarter Asset Management, and you continue to see that come in even during a really challenging quarter, which I think speaks to the Smarter Asset Management and the operating philosophy that we had. You do see, obviously, with higher prices, you're going to see higher production taxes, which is a piece of that stack. But we welcome the higher prices because it gives us the ability to capture additional hedging value as well as realized higher prices on the value -- on the hedges -- on the volumes we haven't hedged. But we are watching G&T, which is the piece of the cost structure that we have the least control over, but as we've grown scale, gives us some ability to continue to work on renegotiating those. We had a rate increase on one of our larger systems that we are working through and obviously reflect that in the first quarter. But it is an area that we'll look to continue to put some focus on and see if we can drive a bit lower as we move forward. But all in, yes, you saw margins still north of 50%. I think we were 52% for the quarter. So I think an exceptional outcome, inclusive of the investments that Rusty said we made on G&A because we did think it was really important to get ahead of a new basin entry. We wanted to signal to you all that we took this very seriously. This isn't a cavalier step out, and so we proactively made the investments in not only the platform, but in our technology so that we can continue to be that much more efficient and scalable as we move forward. So you'll see that same inflection in compression on costs as we do continue to rebuild our scale in a new area.
Yes. The other thing I would say is it's pretty clear that when you still have a 52%, 53% margin, that a lot of those costs are variable. Because what we've seen is prices have increased pretty substantially in the first quarter. The Henry Hub prices have went up and the net prices that we typically experience in winter months went up, but the margins -- as those went up, those costs have come up with them, things like severance taxes, personal property taxes, which are based on revenue. So those things have went up along with the prices. So you definitely will see some price increases related to that kind of thing. The variable costs went up and the G&A costs that we've invested in had went up. The base LOE itself was actually down, and that's the piece that -- that's the operations of the business. And so we -- as we scale up and continue to add assets now in this area, that G&A metric cost will continue to come and compress. And that's exactly what we would have expected it to do.
Our next questions come from the line of Jeff Robertson with Water Tower Research.
I'm sorry. On the Cotton Valley assets, is it right to assume that you're buying the rights on that acreage just to the Cotton Valley or in all formations above it? Or are you -- are there some areas where you're also getting rights to the Haynesville?
It's Cotton Valley and above. Most of the Haynesville will continue to stay with Indigo, which [ there will be ] Haynesville driller and so most of the rights to the Haynesville are being retained by them.
Yes. It's one of the reasons we've been successful in the rollout strategy because we're interested in the PDP and managing the production. I am happy to help hold the acreage or hold the deeper right for the other operator who has an interest in developing it because that's their focus. And it's another reason why we're able to obtain the shallower producing zones at the valuations we do. And certainly, if they chose to come in and develop it, that's just future opportunity for us to acquire as it matures. But that's been true across Appalachia, and it will be true as we step into this new focus region.
Can you talk about what kind of capital program you envision for these assets in 2021?
Well, I don't know what you're referring to in terms of capital program. What I would say is probably little to no drilling for sure. But we will probably have some capital as we assess the assets and we see areas that we may be able to enhance or improve production, or to maybe, in some cases, we will maybe reduce compression, maybe we'll have to spend some money to do that or whatever in the field. But for the most part, I would call it very nominal capital spend. We're not planning on spending much capital here.
It will be optimization focused.
And then lastly on your central region, are there -- do you see more opportunities in this area to -- acquisition opportunities where you could bring in the Oaktree relationship to look at larger deals than you do in Appalachia?
Yes. And the plan is to do that. I think that if you look at this area specifically and then you go up through Northern Texas and into Oklahoma, there's definitely going to be some deals of size there. And that's really the main focus that we brought Oaktree in for. Bolt-ons or new entries of $250 million or less, we feel very comfortable with that and are able to do that without really taking down our own balance sheet. When you start getting about $250 million and starting to get bigger transactions, and really I will even say $250 million is probably in the low end, that $500 million and above is really where they really had the best juice for us. And so they come in, they look at those transactions with us and we're able to use less of our balance sheet, close on more deals with future optionality to buy those assets back from them at some point in the future. So -- but yes, we will definitely be assessing a lot of deals in this area with them.
Thank you. There are no further questions at this time. I would like to turn the call back over to management for any closing remarks.
Yes. So thank you all for joining us today. Again, you can see that we're very, very -- we have a lot of hope for this area. We think that we can add a lot of value here. You will see additional deals as we move forward. And so we are looking for long-term value. We think this area gives us a big opportunity to do that. And we think this is just the start of a lot of different transactions that we can accumulate here. So again, thank you all for your time today, and we'll talk soon.
Thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time. Have a great day.