Northern Oil & Gas, Inc. Q3 FY2025 Earnings Call

Greetings, and welcome to NOG's Second Quarter 2025 Earnings Conference Call. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's Third Quarter 2025 Earnings Conference Call. Yesterday, after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of our website at noginc.com. We will be filing our September 30 10-Q with the SEC within the next few days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows: Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team will be available to answer any questions. Before we begin, let me remind you of our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that have been described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliation of these matters to the closest GAAP measures can be found in our earnings release. With that, I'll turn the call over to Nick.

Thanks, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. I will, as usual, provide you with some highlights on our outlook and five quick points. Number one, the business remains very solid. Our activity remains stable. Our drilling and completion list has continued to march on with high-quality, low breakeven activity, and we remain on target for the year and expect a strong exit into 2026. Number two, we and many of our operators have been cautious and disciplined with our drilling capital. We have explained that being return-driven versus growth-driven means we will react accordingly and be judicious with how we allocate our capital. So far, given the commodity complex, this strategy has proven to be sensible. This allows us to preserve our growth inventory and capital for periods where we can maximize value for our investors and ramp aggressively when it's appropriate in the cycle. Yet we've also grown our gas volumes into a stronger backdrop as we allocate capital accordingly. Number three, it also means we can focus some of our capital for long-term value creation. We have never been busier on the business development front ever. We have been clear that our priorities are focused on creating long-term value, and we believe that disciplined long-term strategic opportunities are best suited in this environment to create value. Our recent minerals and royalty deal typifies this strategy, adding long-term growth, low-risk assets into the portfolio that will prove highly resilient to short-term gyrations in the commodity market. Number four, we've been purposely tactical in regards to our capital stack. The balance sheet management we have undertaken may not be fully appreciated yet, but it is critical to how we navigate the current marketplace. With a tack-on to our convertible earlier this year, our recent bond and tender transaction and the recent extension of our bank facility, we will see some substantive benefits to the corporation. In the current pace, we will exit 2025 with potentially more than $300 million of additional liquidity as compared to the beginning of 2025. We will also see a further reduction in interest rates with our new revolving credit facility terms. We've entered into interest rate swaps to further reduce those rates and can increase this amount if warranted. The extra cash flow, the substantial increase in liquidity and the longer tenure of our debt maturities continues to set us up to pounce on countercyclical investments as we intend to. Number five, we continue to actively manage other risks such as commodity exposure. You'd be hard-pressed to find a better-hedged company than ours. This actively managed hedge program allows us to better navigate the typical commodity cycle. This practice is another factor that protects our business and allows us to continue to take the offensive through trough periods. In summary, the business remains solid as a rock. Inorganic opportunities are more robust than ever, and we've taken substantial steps on the risk and capital management front to ensure our ability to take advantage of any cycle. We firmly believe that NOG has more growth and value-creating prospects than the bulk of the upstream sector, and we look forward in the coming quarters and years to proving this thesis to our investors. Thank you for your interest in our company. And with that, I'll turn it over to Adam.

Thank you, Nick. I'll touch briefly on the operational results for the quarter and then turn to our ongoing business development efforts. Operationally, our assets continue to outperform internal expectations, and we saw this across all of our respective basins. As a result, we've increased annual production guidance while tightening CapEx for the year. While expected turn-in-lines came in slightly under forecast as certain wells were deferred to the fourth quarter, production outperformance was driven by a number of different factors. Notably in Uinta, upsized completion designs have increased overall productivity relative to internal estimates. While in the Williston, we've seen outperformance on recent turn-in-lines and much better execution on refracs as operators continue to refine designs. As it pertains to activity levels, the Permian accounted for about two-thirds of our organic activity, while the Williston and Appalachia evenly made up the remainder of wells that were brought online. Drilling and development activity was also consistent, slightly building our wells in process, adding additional low breakeven backlog and setting up for a strong finish into year-end. Relative to prior quarters, we are seeing a more balanced drilling and completion list as the Permian now makes up 40% of our wells in process, while the Appalachia, Williston and Uinta each make up roughly 20% of the total. New well proposals and election activity have also remained consistent as we received over 200 well proposals and consented to over 95% of AFEs balloted in the quarter. Year-to-date, we have seen 160 more proposals than what was balloted through the same period during 2024. Expected returns remain well above our hurdle rate, further bolstered by a 10% increase in lateral lengths, driving down normalized AFE costs by nearly 5%. In addition to the longer laterals, NOG's operators continue to see downward pressure on service costs for both drilling and completing, which has been encouraging. We should see those operational efficiencies materialize through Q4 and into 2026. Turning to our business development efforts. Q3 was one of the busiest periods in company history as we screened more than 14 large asset transactions and over 200 ground game opportunities, up over 20% relative to the second quarter. While our scaled business model provides more acquisition opportunities than any other in the E&P space, we remain focused on only the highest quality assets and will strictly adhere to our stringent underwriting requirements. As we previously announced, in August, NOG closed on a royalty and mineral interest acquisition in the Uinta that included 1,000 net royalty acres across 400-plus gross locations, excluding the additional inventory that is not currently in our development plan. This is a prime example of how NOG leverages its proprietary database and asymmetric knowledge to capitalize on opportunities in an inefficient market. This acquisition increased NOG's average effective net royalty interest from 80% to 87%, covering the entirety of our Uinta position and further lowering our breakevens in one of the fastest-growing basins in the Lower 48. Our ground game remains as active as ever, closing 22 transactions, executing on three trades that high-graded our acreage position and signing a joint development agreement that covers seven additional extended lateral spacing units. As a result, we added over 2,500 net acres and an additional 5.8 net wells during the quarter, bringing year-to-date ground game additions to over 6,000 net acres and 11.6 net wells across 50-plus transactions in all of our respective basins. NOG's diverse holdings across both oil and gas has provided ample opportunity to deploy capital in both near-term drilling opportunities as well as longer-dated inventory. This has given us the ability to navigate the dynamic competitive pressures that have changed throughout the year. While the broader M&A market has been relatively stagnant across the sector and a lower commodity environment, our unique position counters that thesis, and we do not see things slowing down for NOG. However, the landscape has changed from historical trends. In the past, the large majority of opportunities were concentrated in the Permian. And while we continue to see those prospects, we are seeing a myriad of high-quality potential deals spread across a greater number of basins. Currently, we are screening eight transactions with a combined value of over $8 billion across operated, non-operated, and joint development structures. Additionally, we've been able to approach a number of these assets with various structures, providing optionality to the seller that also works for us. Regardless of the environment, we will remain steadfast in our approach to underwriting and focused on high-quality assets that will generate superior returns for our investors and stakeholders. With that, I'll turn it over to Chad.

Thanks, Adam. NOG's diverse and scaled platform continues to deliver in the face of a challenging macro environment and well performance continues to exceed internal expectations across all of our basins. Third quarter total average daily production was approximately 131,000 BOE per day, up 8% versus Q3 of 2024, and down 2% from Q2 2025 as expected, reflecting the low point for net well additions in 2025 at 16.5. It is important to note that one-third of those net wells came online late in the quarter, providing momentum into the fourth quarter. Oil production was approximately 73,000 barrels of oil per day, up 2% from Q3 2024, and down 6% sequentially. Gas production continues to ramp as our gas joint drilling program is on a consistent monthly turn-in-line phase. Once again, we had record gas volumes of approximately 352 MMcf per day, up 15% from Q3 2024, and up 3% from Q2 2025. With the expectations of adding between 23 and 25 net wells in the fourth quarter, heavy late net well additions and well outperformance in Q3, we have increased our annual production guidance to a range of 132,500 to 134,000 BOE per day. Moving on to our financial results. Adjusted EBITDA in the quarter was $387.1 million, and free cash flow was $118.9 million, marking our 23rd consecutive quarter of positive free cash flow, exceeding $1.9 billion over that time period. We reported a net loss of $129 million in the quarter, which reflects the previously disclosed noncash impairment charge of $319 million. Our adjusted net income was $102 million or $1.03 per diluted share in the quarter. Oil differentials averaged $3.89 per barrel as we saw improved differentials across all of our oily basins. Natural gas realizations were 82% of benchmark prices, consistent with Q2 2025, due to ongoing Waha market weakness and was also impacted by lower NYMEX natural gas prices. Lease operating costs per BOE were down marginally from Q2 2025, despite lower oil volumes. We did see some relief on saltwater disposal costs, but we are still seeing steady expense pressure from workovers. Given the higher run rate year-to-date and the expectation of continued workovers, we have increased annual guidance on lease operating expenses. We have also revised guidance on production taxes to a lower run rate given year-to-date actuals and anticipated production mix in the fourth quarter. CapEx in the quarter, excluding non-budgeted acquisitions and other, was $272 million, reflecting an active quarter on the ground game as discussed by Adam earlier. Overall, the $272 million was allocated with 49% to the Permian, 25% to the Williston, 5% to the Uinta, and 21% in the Appalachian Basin. Approximately $212 million of the total spend in the quarter was allocated to organic development CapEx. With the history of three quarters behind us, we have tightened our full-year CapEx guidance to a range of $950 million to $1.025 billion. At the end of the quarter, we maintained approximately $1.2 billion in liquidity, consisting of $32 million in cash and over $1.1 billion available on our revolving credit facility. We have been actively managing our balance sheet throughout 2025, including since quarter-end. In October, we raised $725 million of notes maturing in 2033 with a coupon of 7.875%. We used those proceeds to retire nearly all of our notes maturing in 2028 that have a coupon of 8.125%. Earlier this week, we amended and restated our revolving credit facility, which extended the tenure to 2030, and markedly improved our pricing grid by 60 basis points, significantly reducing future interest costs. The credit facility's elected commitment amount and borrowing base remained unchanged. These transactions together extended the weighted average maturity on our debt from approximately three years to six years. Importantly, we have no major maturities until 2029. That concludes our prepared remarks. Operator, please open up the line for Q&A.

Your first question comes from the line of Charles Meade with Johnson Rice.

Nick, you touched on the outlook for 2026 in your prepared comments, but could you provide more details on what you're observing? If you intended to provide guidance for 2026, you likely would have done so. I'm really interested in your perspective since you evaluate a variety of operators across many key producing areas in the Lower 48. Could you share what you believe the industry baseline will be and then possibly how NOG might differ from that baseline?

Yes. I mean, I think what you see in the industry is probably what you'll see for us at this point. I mean, I think we haven't seen much change in activity since the prior quarter, which has been relatively flat. And I think that's generally what we would expect as we head into next year. The activity has been very, very stable. I think the commodity outlook may change, and that may change that. And I think that that's why I think things certainly can change as we head into next year. And I think that's why we tend to wait later to guide because I think, frankly, if oil prices were to change materially between now and next year, obviously, activity may change as well. But I think as it stands today, what we've said, and I'd say it would be consistently, would be that to maintain an outlook, I think, on the oil side, similar to where we are this year for our annual guidance, it would require a budget lower. I think in any scenario, and I'm referring to oil volumes, I think we're going to see material gas growth next year. I think if we spend a budget similar to this year, we would see probably growth in both commodities. And so I think the question will really be what's appropriate, right? And I think, obviously, we're watching the commodity outlook. And as I mentioned in my prepared comments, we're very much return-driven. I think it's going to be a combination of operator behavior, project optionality, and things that we see on the ground and where we want to allocate our capital accordingly. I don't know if Adam, if you want to add to that.

Yes. I mean, obviously, everything is going to be driven by breakevens. If we're looking at kind of what our backlog looks like here, we've got a healthy Permian backlog. I think the interesting thing that we've seen in the quarter, especially with the AFEs is on the Williston side, you're seeing kind of weighted average AFE lateral lengths, almost 14,000, 15,000 feet, and that's spread across a multitude of different operators. And so I think that's obviously helping bolster some of the expected rates of return that we're seeing there, lowering normalized well costs and helping again to bolster the expected rate of returns in the basin.

Yes. I would add that the commodity outlook may change. Depending on the developments in the gas sector next year, I believe we will see significant growth in gas regardless. Furthermore, if the gas market expands dramatically next year, we will experience even more organic growth in our assets. This presents another avenue for capital that could change, allowing us to allocate additional capital proactively on the ground.

Got it. That is helpful information on your thinking. If I could focus on the fourth quarter, your annual guidance suggests that we will see sequential growth in that period. Chad, I believe you mentioned in your prepared comments that there are 23 to 25 net wells expected to come online in the fourth quarter. Could you provide us with an update? As we are now in the first week of November, how many of those wells have already been brought online? Additionally, can you discuss whether these wells will be turned in line at the start, evenly throughout, or at the end of the quarter? Just talk about your current status in that process to help us understand your confidence in the anticipated volume increase for the fourth quarter.

I think we are currently on track. It's important to remember that well completions take time; an initial production figure doesn’t tell the whole story. Typically, it takes about 30 days for a well to fully clean up and start producing effectively. If a well comes online in October, its contribution to the quarter is significant but not substantial. Many of the deals late in Q3 will have the biggest impact on Q4, which is the source of our confidence for this quarter. The wells that came online in early Q4 and late Q3, most of which have already started, are really what contributed to our guidance increase along with the overall production outlook. This is the key factor in our anticipated production growth for the year. We expect to see strong production as we move into early next year.

Your next question comes from the line of Scott Hanold with RBC.

Nick, I'd say that you had a pretty strong view on what you're seeing on M&A and ground game and obviously very encouraging. And frankly, I think it's one of the most robust comments to that effect I've heard from you for a while. Can you kind of compare and contrast what you're seeing in the market for that view today relative to, say, a few years ago when you did a number of large acquisitions? And how do you think about funding both ground game and larger transactions if it does meet your hurdle rates?

Well, let's see here. I mean in terms of the robustness of the backlog, I'd say that the one comment I'd make is it's a lot broader than it's been. I think if you go back a few years ago, it was very Permian-centric. Scott, it was very much driven by private equity firm life, and you had a lot of assets being monetized after a long period. And so I think that now you're seeing what we see now is a really broad and robust backlog of multi-base stuff.

Your next question comes from the line of Neal Dingmann with William Blair.

My question, Nick, is centered on your continued activity. Specifically, you all have talked about, I'm just wondering, given the notable changes we've seen in oil prices now still sub-$60 and natural gas now nearly $4.50, are you all getting a sense of things beginning to change into '26, meaning are you seeing some oil activity continue to slow down? And are you seeing maybe potentially some gas activity picking up? Or have you all noticed anything different with prices now in these ranges for, I guess, now a few weeks?

I mean, there’s nothing immediate to report, Neal, and nothing has changed from what we’ve experienced all year. As I mentioned before, I’m not sure where our previous comments were interrupted. But to answer your question, we haven't observed much change in overall activity since last quarter. Oil activity has remained relatively flat and stable. Gas activity has been stable to increasing, but that trend has been consistent throughout the year. Adam, do you want to add anything?

Yes, that's right. I think the Williston and the Uinta have kind of been humming along. And then from more of an inorganic standpoint, we've been focused on deploying capital within Appalachia and then looking at more near-term drilling opportunities that's largely been focused in the Permian based on breakevens.

Well said. And then just, Nick, for you and Adam, just a follow-up on M&A. Two questions on M&A. First, seems like you have a fair amount of assets that I don't know if you're getting full credit for. Are you always considering as part of the M&A strategy? Is monetizing anything? Is that in the game plan? I haven't asked you that in a long time. And then secondly, with the opportunities you're seeing out there, you talked about ground game or deal flow looks as good as ever. Is it a mix? Are you seeing the potential for large deals like whatever, the SM Vital deals that you've done in the past for all these mostly small deals? What are the types of opportunities you're seeing?

I believe it's a combination of various factors. Recently, our royalty deal was relatively modest, around $100 million. We have observed transactions ranging from $100 million to $1 billion, with the billion-dollar deals setting a very high bar in terms of financeability. Overall, we are seeing a wide range of transactions. I'm not sure if you want to add anything else.

Yes. I think the bell curve is relatively wide. To Nick's point, right, we signed up the mineral deal at $100 million. There are deals out there that are $4 billion, and you've got everything kind of in between. I think the other tool in our toolbox is that we can approach a handful of these transactions with different structures, right? You can buy down an undivided interest and make a non-op interest out of anything. And so if we're thinking about co-purchases, could you also approach that from a joint development agreement perspective? So I think there's a handful of different ways that we can kind of shape these assets that others might not otherwise be able to.

Your next question comes from the line of Scott Hanold with RBC.

And Nick, I guess to my first M&A question, I think where it cut off is when you were differentiating between now and, say, a few years ago; you were mentioning it was broader. And I guess just to finish off that question, I guess, would be the funding, how you think about funding for that? And then I'll have my follow-up after that.

Yes, I think my previous points were interrupted, but I want to clarify this: regarding funding, we've addressed this question publicly many times before. Our funding approach remains consistent. If you believe we have a solid understanding of corporate finance at both the Board and management levels, it follows that we'll finance any transaction only if it benefits our stakeholders. We will do so in a way that supports their long-term interests and minimizes risk. As I noted in my prepared comments, we possess a significant amount of liquidity at favorable costs, around sub-6%, and we have multiple other options available should we need to use those sources, but we will only proceed if it makes sense.

Okay. Understood. And then my follow-up question is, Adam, you were talking about lateral lengths and how they're increasing. Could you all just give some kind of context for us on how broadly you're seeing that lateral length increase? And how does that impact your capital efficiency and decline rates moving forward?

Yes, I can start and then pass it over to Jim for comments on the decline rates. We're observing this trend across all our basins. In the Williston during Q3, we're seeing lateral lengths of 14,000 to 15,000 feet, which includes over five operators and more than 80 drilling approvals during the quarter. The same trend is visible in Appalachia and the Uinta, where, in collaboration with SM, we're also starting to extend lateral lengths. Even in the Permian, we are observing some of the longest average lateral lengths to date. This trend puts downward pressure on the weighted average AFE normalized costs and enhances expected returns. The key insight we've gained over time has been regarding how they've accessed the reservoir, and now I'll hand it over to the engineer.

Yes. Thanks, Adam. Yes, like we said, we're seeing operators continue to refine their completion designs, more effectively stimulate the toll of the well and be able to draw down the pressure. What you'll see is they're not going to overdesign the facilities. So you're not going to see a straight ratio going from a 2-mile to a 3-mile where the IP is going to go up by 50%. It's going to go up a little bit. What you're going to find is you're going to find that the well is going to stay flat for much longer and then have shallower declines. Now we typically are a little bit more conservative. And so what we'll see is when we see that IP rate, we'll continue to maintain our prior decline rates until we have more information. That might take 6 to 9 months. And so what we're seeing now is that these wells are holding in there a little bit flatter for a little bit longer. So they're starting to exceed our expectations from what we initially expected. So as we continue to get more information, we'll continue to refine our expectations and our decline curves moving forward.

Your next question comes from the line of John Freeman with Raymond James.

Just following up on the nice progress on the AFE dropping to $806 a foot this quarter versus the $841 last quarter. Can you give us kind of like you did last quarter, where the well cost stands on your current drilling and completion list on a per-foot basis?

Yes. I think it's going to largely be similar. I mean, if you're looking at the AFE lift from last quarter, that's going to largely translate to what we're seeing on the drilling and completion list now. So the expectation, I don't have the information in front of me, so I can follow up with you, John, but I would expect that it's slightly higher. Jim was able to pull it up, and it looks like it's coming in kind of average at $821, give or take.

Okay. Perfect. And then my follow-up question, you all mentioned in the slide deck, you still got, obviously, the significant shedding and deferred volumes. And I'm just curious like where that number stands right now and if it's been continuing to grow.

Two to four is kind of what we're seeing. And operators, particularly the private ones, tend to cycle that, right, from a lease maintenance standpoint. And so I don't think we necessarily see that appreciably changing at this point.

Your next question comes from the line of Paul Diamond with Citi.

Just wanted to quickly touch on AFEs. You talked about a 5% sequential well cost reduction, noting lateral length, but was there anything else in those numbers? And I guess, any other contributions and any opportunity that you see for kind of continuing that trend?

Yes. Our observation has been that the main source of cost savings recently comes from increasing lateral lengths and improving efficiencies. We haven't noticed a significant reduction in service costs. In fact, as we've mentioned regarding lease operating expenses, inflation is a real factor. We're addressing that by drilling longer laterals and reducing drilling days to cut costs. To achieve substantial savings at the well level and to see significant cuts, I believe we may need to see a further decrease in overall activity. If oil prices were to drop significantly again and we experience another decline in the rig count, I anticipate that we would see major concessions. We've spoken with several of our large operators who are discussing what they refer to as vendor management. Essentially, they are empowering their field teams at the basin level to choose their vendors and are now considering centralizing this process to reduce from about 50 or 60 vendors down to around nine to enhance their bargaining power. As this strategy is implemented, it could potentially lead to additional cost reductions over time, but we'll have to wait and see.

Yes. And you're going to see that on a rolling basis, right? And it's going to be spread across the operators because they've obviously got to see these contracts through. And then once they roll off, then that's going to be your window.

Yes. We are entering budgeting season and a new year, which may lead to changes in contracts. This could be a time when we start to experience some cost relief, but we will have to wait and see.

Got it. That makes sense. I have a quick follow-up regarding the broader situation. You mentioned refracs. Can you discuss any changes in activity that you've observed in recent quarters and what might be expected in the near future? This has become quite a relevant topic lately.

Yes. I mean as far as the refracs go, that's primarily been concentrated within the Williston. And I think historically, operators have deployed those refracs, and it's been a bit of a learn as you go. And so I think this quarter, we saw some appreciable uplift. And so I think it's maybe still early days as far as what we would look to change our kind of underwriting and expectations there, but it seems like operators are moving up into the right.

Your next question and final question comes from the line of Noah Hungness with Bank of America.

For my first question, I was wondering if you could talk about what's driving the continued build in wells in progress and when you think that number will start to decline? And if the higher TIL count for 4Q versus 3Q would ultimately result in a drawdown on the wells in progress.

I think that's a difficult question to answer, Noah. As it stands now, we've seen very steady AFE activity. If this activity continues, we would expect it to remain relatively stable. However, if there is a significant change in commodity prices, we could see it potentially decrease.

Yes. I think the other variable that you got to think about, right, is you've got gross activity levels, but then you need to think about average working interest on those AFEs, and that can certainly be variable. So from a gross perspective, everything has been kind of humming along. But from a net level, that can vary from quarter to quarter. And so if you're looking at just activity quarter-over-quarter, that can fluctuate.

Yes. However, if the question is whether we anticipate an imminent change, the answer is no. It could happen, of course, but ultimately, it will be determined by the environment. Our perspective is that if prices experience a significant change from this point, we would expect activity to either increase or decrease accordingly.

Yes. The only other thing, I guess, I'd add is stacked pay co-development, are you drilling two wells on a pad? Or are you drilling 12? And the spud to sales timing is going to be wildly different between kind of those two scenarios.

No, that's helpful color. As for my second question, based on 3Q results and the updated '25 guidance, going back to kind of thinking about implied 4Q oil production, the range is pretty wide. So could you help us think about maybe some of the moving parts there that could put you at the midpoint or below or above in that range?

Yes, it's really about the timing of completions. As a nonoperator, we have to give ourselves some leeway on that timing. It is indeed about timing, and we expect to tighten it up as the year progresses. Regardless, we anticipate a significant increase as we end the year. Additionally, with base production improving and overall declines moderating, we are set up for a solid start to the first half of next year. The key question will be how much capital our operators choose to deploy and how much we want to allocate on a discretionary basis for next year, which will influence our targeted activities and ultimately drive our results. This will be a decision based on returns.

That concludes our Q&A session. I will now turn the call back over to Mr. O'Grady, CEO, for closing remarks.

Thanks, everyone. NOG is well positioned to navigate through the current market volatility. Our assets are performing very well. Our liquidity is abundant, and our investment opportunity grows every single day. We're really grateful for being aligned with strong and capable partners, and we look forward to keeping you informed on all our activities and achievements in the coming weeks. Thanks again for your interest in our company. This is the way.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. Everyone, have a great day.