Magnolia Oil & Gas Corp Q1 FY2024 Earnings Call

Good morning, everyone, and thank you for participating in Magnolia Oil & Gas Corporation's First Quarter 2024 Earnings Conference Call. My name is Megan, and I will be your moderator for today's call. At this time, all participants will be placed in a listen-only mode as their call is being recorded. I will now turn the call over to Magnolia's management for their prepared remarks, which will be followed by a brief question-and-answer session.

Thank you, Megan, and good morning, everyone. Welcome to Magnolia Oil & Gas' First Quarter Earnings Conference Call. Participating on the call today are Chris Stavros, Magnolia's President and Chief Executive Officer; and Brian Corales, Senior Vice President and Chief Financial Officer. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company's annual report on Form 10-K filed with the SEC. A full safe harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's first quarter 2024 earnings press release as well as the conference call slides from the Investors section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Chris Stavros.

Thank you, Tom, and good morning, everyone. We appreciate you joining us today for a discussion of our first quarter 2024 financial and operating results. I will provide some comments on our first quarter, noting the progress of our development plan so far this year, discuss an important bolt-on acquisition that we recently completed and highlight some actions we're taking at the field level to reduce our cash operating costs. Brian will then review our first quarter financial results in greater detail and provide some additional guidance before we take your questions. Starting on Slide 3 of the investor presentation. Magnolia delivered a strong first quarter with total adjusted net income of $101 million. In keeping with our consistent business model, we continued our capital-efficient D&C program by spending $119 million or 52% of adjusted EBITDAX while generating $117 million of free cash flow. As part of our goal to return a significant portion of our free cash flow to our shareholders, we returned 68% of our free cash through our ongoing share repurchase program and our recently increased dividend payment. Total company production was towards the top end of our guidance at 84,800 barrels of oil equivalent per day, representing year-over-year production growth of 7%. Production at Giddings was 61,400 BOE per day, providing overall growth of 17% compared to last year's first quarter, including oil production growth of 16%. Total company oil production during the quarter was ahead of expectations, coming in at 37,500 barrels of oil per day, benefiting from strong well performance, activity in Karnes and solid performance from the assets we acquired late last year. We had planned for this year's program to be a little oilier than last year and our first quarter production provides some early evidence of that plan. Last week, we closed on a very meaningful bolt-on acquisition of oil and gas properties in the heart of our Giddings acreage. These assets were acquired from a private operator for $125 million and have similar attractive operational financial characteristics to our core acreage position in Giddings. As I've often mentioned, the key part of our strategy is to use some of the excess cash generated by the business to seek out attractive bolt-on acquisition opportunities with the goal of making Magnolia better, not by simply replacing the oil and gas that is produced but to improve the future opportunity set of our overall business and enhance the capability and sustainability of our high returns. This latest bolt-on acquisition adds new high-quality acreage that is contiguous to our existing core footprint in Giddings, while also increasing our working interest in some of our current acreage. The transaction leverages the significant knowledge we have gained through operating in this field and extends our deep inventory of high-return development opportunities in Giddings from both new locations and incremental working interest. As shown on Slide 4, the majority of the properties are located in the core of Giddings with acreage in Washington, Lee and Fayette Counties, representing an additional 27,000 net acres spanning over 80,000 total gross acres. The properties include a relatively small amount of base production of approximately 1,000 BOE per day and about 35% oil with Magnolia operating most of the volumes. This is an ideal acquisition for Magnolia, which significantly enhances our position in Giddings and strengthens the company moving forward. Magnolia continues to operate 2 drilling rigs and 1 completion group with the majority of this year's activity planned in Giddings. Our full year 2024 guidance for D&C spending remains unchanged and is expected to be in the range of $450 million to $480 million. Following on last year's success in reducing our well cost by nearly 20%, our drilling and completions have gotten off to a strong start in 2024, and we continue to drive further operating efficiencies. While this year's program includes drilling somewhat longer laterals, we have realized considerable recent improvement in reducing our drilling days per well. Lower well costs combined with improved operating efficiencies allow for more wells to be drilled, completed and turned in line during 2024, helping to support Magnolia's overall high-margin growth. As I mentioned earlier, we expect this year's development program to be oilier than last year and our strong first quarter oil volumes support the plan. We anticipate that this year's oil production should remain resilient as a portion of our activity will focus on some of the oilier assets acquired last year. Some of our drilling activity leaned away from natural gas early in the year due to very weak prices, and we expect that our natural gas production should reassert its growth as the year progresses with the view that gas prices would see some recovery later in the year. Lastly, our operations and supply chain teams have initiated a field level optimization and cost reduction program throughout our assets. Part of these efforts will employ improved field management systems that will increase efficiencies and optimize processes across the field and targeting such areas such as contract labor utilization, surface repair and maintenance and procurement just to name a few, while capturing synergies from the acquired assets. These and other initiatives to lower our cash costs are expected to deliver a 5% to 10% reduction in our cash LOE per BOE during the second half of the year compared to the first quarter. As Magnolia has grown and learned while operating our assets over the past 6 years, we believe this is an appropriate time in our evolution to embark on this program. Our goal is to improve on our track record for generating high operating margins while providing additional free cash flow to either return to our shareholders or efficiently reinvest in the business, and these actions should help us achieve these objectives. I'll now turn the call over to Brian to provide more details on our first quarter financial and operating results.

Thank you, Chris, and good morning, everyone. I will go over some highlights from our first quarter results and reference the presentation slides available on our website. I will also give some guidance for the second quarter of 2024 and the rest of the year before we open the floor for questions. Starting with Slide 5, Magnolia had a strong first quarter overall. We reported total GAAP net income attributable to Class A common stock of $85 million and total adjusted net income of $101 million, or $0.49 per diluted share. Our adjusted EBITDAX for the quarter reached $228 million, with capital expenditures related to drilling, completions, and associated facilities amounting to $119 million, which is 52% of our adjusted EBITDAX and nearly 10% below our guidance. Total production volumes grew by 7% year-over-year to 84,000 barrels of oil equivalent per day, and our diluted share count decreased by 5% year-over-year to 204.3 million shares. Referring to the cash flow waterfall chart on Slide 6, we began the year with $401 million in cash. Our cash flow from operations before changes in working capital for the first quarter was $218 million, with an increase of $6 million from working capital changes and other items. We invested $27 million in bolt-on acquisitions, primarily in Giddings, paid out dividends of $27 million, and put $51 million towards share repurchases. Total capital amounted to $121 million, and we ended the quarter with $399 million in cash, relatively unchanged from year-end 2023. Slide 7 illustrates the progress we have made in reducing our total outstanding shares since we began our share repurchase program in the second half of 2019. We have repurchased 64.3 million shares, resulting in a net change in diluted shares outstanding of over 20% after issuances. Magnolia's weighted average fully diluted share count fell by more than 2 million shares sequentially, averaging 204.3 million shares in the first quarter. We still have 6.9 million shares left under our current share repurchase authorization, specifically for repurchasing Class A shares in the open market. On Slide 8, we note that our dividend has significantly increased over the past few years, including a 13% rise announced earlier this year to $0.13 per share on a quarterly basis. Our next quarterly dividend will be payable on June 3, offering an annualized payout rate of $0.52 per share. Our plan for annualized dividend growth is a key component of Magnolia's investment strategy and aligns with our overall aim of achieving moderate annual production growth, reducing outstanding shares, and enhancing the company's dividend capacity. Magnolia enjoys a robust balance sheet, ending the quarter with approximately $0 net debt and $399 million in cash. Our $400 million principal debt is included in our senior notes, maturing in 2026. Adding our cash balance of $399 million and our undrawn $450 million revolving credit facility, our total liquidity stands at about $850 million. Our condensed balance sheet as of March 31 is displayed on Slide 9. Moving to Slide 10, we examine our per unit cash cost and operating income margins. Total revenue per BOE has decreased year-over-year due to lower natural gas and NGL prices compared to the first quarter of 2023. Our total adjusted cash operating costs, including G&A, were $11.86 per BOE in the first quarter, down by $0.79 per BOE or 6% from a year ago. This decrease is primarily attributed to lower production taxes in GTP. Our operating income margin for the first quarter was $16.15 per BOE, which is 39% of our total revenue. The year-over-year decline in our pretax operating margin was mainly due to lower commodity prices and a higher DD&A rate. Regarding our guidance, we are reaffirming our expected 2024 drilling and completions capital spending to be between $450 million and $480 million, which includes a non-operating capital estimate similar to 2023 levels. We anticipate total production and oil production to see high single-digit growth annually. For the second quarter, we expect our drilling and completions and related capital expenditures to be approximately $120 million to $125 million, with total production projected to be around 89,000 barrels equivalent per day. We expect oil price differentials to be approximately a $3 per barrel discount to Magellan East Houston, and we remain unhedged for all oil and natural gas production. The fully diluted share count for the second quarter of 2024 is expected to be around 203 million shares, a 4% reduction from the second quarter of 2023. Our effective tax rate is anticipated to be about 21%, and with rising oil prices, our cash tax rate is expected to range from 9% to 10% for 2024. We are now ready to take any questions.

We will now begin the question-and-answer session. Our first question comes from Neal Dingmann with Truist.

We have consistently discussed returns in terms of breakeven. Could you provide an update on the current breakeven at Giddings? Additionally, how does this breakeven compare to that of Karnes or Chris, and what are your thoughts on the returns now compared to a year ago?

Yes, I certainly wish gas prices were a little bit better. But frankly, all in all, the Giddings wells have better full cycle returns than the wells we drill and complete in Karnes. I mean that's just the basic, frank thoughts around it. The Giddings wells, certainly in our core area and most of the wells we drill, often pay out in a year or less. And we've talked about this quite often that they produce more oil over their life than a typical Karnes well. So the Giddings well returns are very high and even in this environment. And so you wouldn't do anything necessarily differently in terms of skewing or slanting or activity to Karnes per se, just to sort of capture return, and the Giddings wells also have a shallower rate of decline. So I think it benefits us all in all.

And Chris, how much have you brought down the breakevens as your operational efficiencies have continued?

Well, our well costs have come down quite a bit, and much of that was captured through our efforts last year by working with our service providers and material vendors. And I said this before, we probably brought well costs down about 20%, and some of that is continuing into this year. So the well costs are currently probably $1,100 a foot more or less and probably coming down a little bit further. We've made some inroads, as I said, too, on drilling faster. So things are just working out real well on that side. So the efficiencies and the breakevens are sort of continuing to come down a little bit.

Could you provide more details on the recent $125 million deal, specifically how it improved your opportunity set in terms of location and other factors?

Yes, sure. We've said this for a long time, and I know Steve used to say it, but it's true. The way to make money in the business, the oil business is to either guess right on the commodity price or require attractive optionality at a low cost or maybe even for free. And when it comes to PDP deals, you're going to pay full value or strip prices for that at the very least. And there's not much to that in terms of real upside. I'm not looking to inherit a lot of production and have to overcome a decline rate. So this particular deal, this is a sort of a great fit in terms of what we look for as far as our bolt-on strategy, specifically lower PDP volumes, but very importantly, significant high-return development opportunities at a low cost and with potential upside. And so we showed this on the map or at least tried to set a lot of new acreage and increased our working interest in existing acreage in a very, very productive area of Giddings right next to or to where we've been busy with our current development. So this transaction represents a unique opportunity, and I'm very confident that it provides us with a minimum of probably a couple of years of high-return net drilling locations and at our current pace of drilling in Giddings. So I think that it's more here than meets the eye and frankly, more bang for the buck.

Our next question comes from Leo Mariani with Roth MKM.

Wanted to start off with just focusing a little bit here on oil cut. So oil cut was definitely, I guess, stronger than expected in the quarter. Just wanted to kind of get a sense of how you kind of see that playing out. I think it's kind of the highest quarterly oil cut you had in a couple of years here. Do you think that can kind of get maintained throughout the course of the year? I know some of the focus a little bit more on some of the oilier drilling? Or do you see that maybe starting to soften as we get later in the year?

So for the first quarter of production, we obviously, as I said, saw good performance, strong overall well performance across the business. Strong performance from the assets that we acquired. We had some oilier Karnes activity that came online during the quarter. This year's development plan will be oilier than last year in our first quarter volumes on oil support that. Some of the drilling, as I said, leaned away a little bit from natural gas early in the year, but that should recover and reassert itself as I said, as the year moves forward. But I also expect that this year's oil production is going to remain pretty buoyant as a portion of our activity is going to focus on some of those oilier assets that we acquired. So rather than simply focusing on the oil mix or percentage, I would characterize our absolute oil volumes as having the ability to remain pretty robust throughout the year. So that gives you a little color. It's going to be a little lumpy as we move forward quarter-to-quarter as it typically is. But I think oil is going to be pretty good, and that was part of the plan.

And then just going back to the acquisition that you did here. So, it sounds like you guys are pretty excited about it. I certainly noticed that you're not changing your production or capital guide for the year. I know it adds kind of a small amount of volumes, but that kind of maybe implies that you're not doing a whole lot in terms of D&C on the asset this year. Just kind of want to get a little better sense for what your plan is? Is it something you're going to integrate in the program next year in terms of drilling? I know some of this is just additional interest on what you already own, but presumably, there's some new stuff to drill as well. And then just do you see other opportunities like this out there? I guess it's kind of your second bolt-on in the last 6 months. So just trying to get a sense of what the plan is going forward.

It's a lot to unpack. Regarding our guidance, part of my responsibility is to manage external expectations while ensuring we can deliver solid results. Currently, our drilling and completion efforts are performing well. The production volumes from the recent acquisition reflect the current output of those assets, and since we will only own them for two-thirds of the year, the overall production impact is minimal. This is acceptable because we did not acquire these properties for the produced developed property; rather, we are focused on the quality of undeveloped opportunities, which I believe are quite significant. There may be a hint of conservatism in my approach or perhaps a touch of caution, but I prefer to maintain straightforward guidance. Therefore, I expect our total production and oil production to grow in the high single digits this year, possibly even higher. As for the acquisition, timing these opportunities can be challenging. This process began evolving last year and was unique for a private operator. I won’t assume to speak for those making personal decisions, but it required considerable effort and collaboration from both parties to finalize. I genuinely hope there will be more opportunities like this in the future. Our goal is to pursue acquisitions that enhance our capabilities without simply growing in size. We aim to maintain our high margins and business model for the long term. This acquisition will integrate into our broader Giddings program, folding in wells this year and more next year; it will essentially reflect the Giddings structure.

Our next question comes from Charles Meade with Johnson Rice.

Chris, I want to take another run at the acquisition. And I'm wondering if you could characterize for us how developed it is in the target zones you're going after? And then maybe that might differ if you have more than one target down the column. How undeveloped is it in your targets? And how many net locations do you think you're bringing in?

It’s not very developed at all; in fact, I would describe it as completely undeveloped. There’s a lot of easy opportunity here, and the potential for upside is significant. There’s a lot of potential for us in this area. It’s unique, and I’m confident we’ve secured several years’ worth of net locations because we understand this area very well from a subsurface perspective. Our ability to drill wells that resemble some of our best-executed pads and wells in the core Giddings areas is a strong advantage. I'm quite excited about our success in this endeavor, and we’re currently looking at a couple of years' worth of drilling at our present pace.

Our next question comes from Oliver Huang with Tudor, Pickering, Holt & Company.

As you all continue to bolt on in the Giddings area, which you've acknowledged having better relative economics to the inventory that remains in Karnes, generally speaking. How should we think about the mix of capital allocation between Karnes and Giddings versus that 80-20 split that you are running this year on a go-forward basis?

Yes. Thanks for the question. I think it's going to be about that more or less. I don't see it changing dramatically. And otherwise, and I'm speaking, operated, non-operated and on Karnes, and it's a little hard for us to predict. But generally, that 80-20, I think, sort of applies here for a while as far as I can see right now.

And maybe just to touch on efficiencies a little bit more. You previously kind of mentioned how the frac side of things was a big driver of lower well costs last year in that the drilling side is a much bigger focus for 2024. Just wondering if you can maybe talk to the progress you've seen to date and also when we're kind of looking at the Q1 CapEx coming in a little bit below your guidance, if there's any color behind if it was more well cost efficiency driven, working interest or just more of a timing aspect?

I believe there is definitely an element of timing involved, which is why some of the capital was pushed into the second quarter. There will always be small timing issues with this. We might see more of that depending on the situation. The numbers from the first quarter and the guidance for the second quarter are somewhat in line with expectations as they currently stand, without accounting for any potential improvements we could achieve. If we can drill more quickly, that will have some positive effects. This situation could bring additional aspects into consideration, which is beneficial as it provides us with more flexibility and options for the rest of the year. Overall, this is a positive development for us. On another note, the ongoing weakness in natural gas prices continues to influence materials pricing, with OCTG also experiencing some price softness, likely in the single digits for the second quarter. I can tell you that there is plenty of availability for rig and pressure pumping crews, as operators are competing on price, quality, and performance. I believe we will see some of these minor benefits reflected in the well cost estimates I mentioned earlier.

Our next question comes from Jack Zach Parham with JPMorgan.

First, I just wanted to ask on the cash return program. You've been pretty consistent for quite some time with the buyback. But you've got a lot of cash on the balance sheet. At some point, could it make sense like accelerate the buyback and use some of that cash to buy back stock?

It could. I appreciate the consistency of the program and the model. While I prefer not to specify an exact number, it seems that within this range of product pricing, you're looking at approximately a two-thirds return of free cash flow, along with a combination of share repurchases and dividends. There may be some flexibility regarding share repurchases due to our sensitivity to price. If the stock underperforms for reasons we can't justify, we're open to adjusting our approach. Ultimately, we'll see how things unfold. I'm not inclined to keep excessive cash on the balance sheet, as I've previously mentioned, we're not a bank. Such a situation can impact our returns, and I'd prefer to utilize cash to generate better returns when possible. Currently, having no significant net debt is quite comfortable and reassuring for stakeholders, but it’s not necessary to have so much cash on hand.

And my follow-up just on LOE. Can you give us a little more detail on what you're doing to reduce LOE and maybe any thoughts on what LOE looks like in Q2 before declining in the back half of the year?

Yes, we've already begun this process. While we're just starting to discuss it now, we've been working on it for a little while. I hope you'll notice some improvements even before the second half of the year, and particularly in the second quarter. However, I believe the most significant improvements will be more apparent in the third and fourth quarters. I'm quite confident that the first quarter will have the highest cash operating costs per BOE for the year. We'll be implementing various field management systems to enhance efficiencies and optimization, including optimizing contract field labor, surface repair maintenance, and procurement synergies from the acquired assets. There are many easy opportunities for us to capture. You could consider this a form of spring cleaning; we've been managing Giddings and Karnes for the last six years and have learned a lot in that time. Now seems to be the right moment to pursue these changes, especially as we're in a stronger part of the cycle. This allows us to look for improvements in a more deliberate way, rather than having to react impulsively or make harsh decisions in a weaker environment. Our field teams support this initiative, and I believe it is beginning to yield positive results.

Our next question comes from Noah Hungness with Bank of America.

I just wanted to ask a quick question here on the deal again. It looks like it fills in a lot of acreage gaps. Does this allow you guys to potentially have longer laterals than the 8,500 feet that you guys are drilling this year? Or does it unlock potentially stranded acreage? And then also, are there any contingency payments associated with this deal similar to what we saw with the November, the deal that closed in November?

No, there are no contingency payments at all. The cost of the transaction is as we stated. Regarding longer laterals and unlocking additional acreage, yes and yes. I won't say that all the wells or locations will exceed the average length of 8,500 feet that we are currently drilling this year, but I do expect that some will be longer for sure. We are examining what this could unlock in terms of lease lines and so on. I believe there is more opportunity in this area.

And then just switching over to the oilier assets you guys are looking to drill later this year. How do those economics compare to core Giddings today, just given how the forward curve has moved up. And could you give any color on maybe when you think those wells will come online 3Q or 4Q?

Yes, you will likely be able to see that later this year in the available data sets. There will be some quantifiable production information. In terms of returns, these wells are indeed oilier than the typical Giddings wells, but it's important to highlight that they are shallower, at 3,000 to 4,000 feet less than our usual Giddings wells. This results in lower drilling and completion costs, making the economics quite similar to those of our core Giddings wells.

Our next question comes from Ati Modak with Goldman Sachs.

I have a quick question regarding your cost reduction efforts. It seems like you are just starting your cost reduction plan now. Many of your competitors have been implementing various strategies over time to achieve cost savings. Could you help us understand where you expect to be after this initial phase of your journey compared to others? This would help us assess the potential for further cost reductions.

I believe starting with a target of 5% to 10% is quite promising. We will monitor our progress closely. We haven't explored this extensively yet, so I see potential opportunities ahead. After six years of work, I liken our situation to spinning in a dryer; the longer we're engaged, the more insights we gather. Occasionally, we need to reassess and adapt. There's still much we can target, and our understanding of our assets has significantly improved. We've drilled numerous wells in Giddings, giving us better insights. I believe there are synergies between our core focus and the implementation of certain field management systems that will enhance our processes. While we will see how it unfolds, I'm hopeful that we'll begin to realize early benefits before the latter half of the year, and we'll continue to track our progress. Ultimately, our goal here is to enhance our operating margins. As our cash costs decrease, our operating margins should increase, resulting in better earnings and more free cash flow. That is genuinely our aim.

And then, I guess, taking that into consideration, how does this plan tie into the long-term sort of efficiency objectives, capital efficiency objectives? And as you free up more capital, how should we think about that allocation strategy?

This is more of a field exercise than a capital exercise. Ultimately, both actions involve money. The capital aspect is incorporated into your finding and development costs and your depreciation, depletion, and amortization. This ends up being your largest expense. By reducing well costs, you can achieve greater drilling efficiencies over time, leading to increased free cash flow and a lower reinvestment rate for the same results. They are clearly interconnected. We will explore some elements, as there is likely overlap in what we can do effectively on the capital side that can be applied based on our field experiences.

Our next question comes from Hanwen Chang with Wells Fargo.

I want to follow up on the investment rationale behind the new Giddings acquisition. Could you perhaps provide some color on some of the key valuation metrics of the acquisition?

Yes. Well, it didn't get a whole lot of volume. So I'd imagine if you back out just the value of the current PDP, you're looking at 3,000 to 3,500 an acre, something like that I'm not sure what all I can say. I think that's pretty attractive, frankly.

And do you have any preferences regarding oil ratio for future acquisitions?

No, I don't see it that way. I focus on how it will enhance our business and financial results, as well as how it supports our ability to manage our business model. This model is entirely geared towards being the most efficient operator and drilling the best wells at the lowest cost to generate as much free cash flow as possible for our shareholders while also reducing the share count over time. We are not looking to increase our debt or sell stock. Everything we've accomplished has been through cash generated by the business. That remains our strategy.

Our next question comes from Sean Mitchell with Daniel Energy Partners.

Congrats on the deal. Deals are not easy to come by these days. So congrats to you guys for getting something done. Several of your peers are doing refrac work, and I think there's more buzz today than there has been in the Bakken, the Eagle Ford. How are you guys thinking about this opportunity, if at all?

Yes, it's more in the, if at all, category.

I know that's fair. I mean there's lots...

I appreciate the question, Sean. I understand your concern. It is really too early for us to consider this in a wide-ranging way. These are preliminary science projects. Honestly, we have a lot of other priorities that are far more pressing. There are too many tasks for us to focus on before we even get to that point. I just don’t see it being part of our strategy in any significant way for quite some time.

Yes, fair enough. And maybe a follow-up on the bolt-on, I think I probably know the answer, but were these guys running a rig or no?

They were not... To my knowledge...

And then of the 2 rigs and 1 frac crew you guys have today, remind me, are those on spot? Or do you guys have those contracted?

Contracted.

Our next question comes from Paul Diamond with Citi.

Just a quick one on kind of the opportunity set or how y'all are seeing Giddings. How should we think about that geographically? Is that more north of Lee, more Eastern Washington, just kind of just a generalized scale of that similar to the bolt-ons or a lot more of the smaller type opportunity still available?

We certainly have a lot to focus on in the areas you've identified. There's also a significant amount of land in other counties within the Giddings Field and Giddings Proper. We will continue with some appraisal work to gain a clearer understanding and better define additional areas that have performed well, leading us to explore new opportunities, whether for acquisitions or new drilling areas with strong economics. It’s still relatively early, and we can't tackle everything at once. The pace at which we can proceed will depend on the financial resources available to us at any given time and our execution plan. We can't do it all immediately, but over time, there will be plenty to explore.

How do the opportunities compare in scale? Are they more like small initiatives or are they similar in size to the acquisitions we've completed this quarter?

I want to emphasize that it would not be accurate to expect a similar transaction to what we just completed again. However, there may be opportunities for smaller fill-ins or select properties that can enhance the areas we are focused on and that are performing well for us.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.