Mach Natural Resources Q3 2026 Earnings Call Transcript

Mach Natural Resources (NYSE:MNR) reported third-quarter financial results on Friday. The transcript from the company’s third-quarter earnings call has been provided below.

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Summary

Mach Natural Resources reported Q3 2026 production of 147,000 BOE per day, with oil contributing 15%, natural gas 69%, and NGLs 16%.

The company generated $319 million in total revenues, with an adjusted EBITDA of $183 million and operating cash flow of $165 million.

Mach Natural Resources maintained a strong focus on disciplined execution of its four strategic pillars: asset acquisition at discounted prices, reinvestment rate under 50% of operating cash flow, financial strength with a leverage target below one times, and maximizing distributions to unitholders.

The company intends to slow down its drilling pace in Q4 to maintain its reinvestment discipline, with expectations of increased cash distributions in early 2027.

Mach foresees increased demand for natural gas by 2028 and has plans to potentially expand drilling activities in the San Juan basin.

For 2027, Mach plans to operate two oil rigs and complete several DUCs in the San Juan, aligning with their strategy to focus on high-return drilling opportunities.

Management remains optimistic about maintaining high cash returns and sees potential in both the oil and natural gas markets.

The company ended the quarter with $31 million in cash and $250 million of availability under the credit facility.

Full Transcript

Melissa (Investor Relations)

Good morning everyone and thank you for joining us, and welcome to Mach Natural Resources’ third quarter 2026 earnings call. During this morning’s call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance, and the assumptions underlying such statements. Please note, a number of factors may cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in their press release and in other SEC filings.

For a further discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements, please read the company’s filings with the SEC. We recognize that, except as required by law, they undertake no duty to update any forward-looking statements and you should not place undue reliance on such statements. They may refer to some non-GAAP financial measures in today’s discussion. For a reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach’s website, and their 10-Q, which will also be available on their website when filed.

Today’s speakers are Tom Ward, CEO, and Kevin White, CFO. Tom will give an introduction and overview and Kevin will discuss Mach’s financial results, and then the call will be open for questions. With that, I’ll turn the call over to Mr. Tom Ward.

Tom Ward (Chief Executive Officer)

Thank you, Melissa. Welcome to Mach Natural Resources’ third quarter earnings update. With each quarter, we reiterate the company’s four strategic pillars that have guided us since our founding in 2017. The first pillar is disciplined execution. We only purchase cash-flowing assets at a value of PDP, PV-10 or less, and do not pay for any leasehold, PUDs, midstream, or infrastructure. In today’s market, there’s a lack of opportunity for investment at the discount we demand. Even in small packages, we’re seeing aggressive bids on oil and bid-ask disagreement on natural gas assets. Therefore, we remain on the sidelines until a market disruption occurs.

Our business is cyclical. We feel there will be a time when some areas experience enough distress to allow us to acquire at our desired levels again. The second pillar is a disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. In 2026, our summer drilling program in the San Juan Mako Shale made our CapEx higher in Q2 and Q3 versus the first quarter and the projected amount in the fourth quarter. The higher CapEx spending for these two quarters resulted in lower distributions paid in August and later this month. The offset will be higher distributions in February and May next year.

We have slowed our drilling pace to one Oswego rig in Q4 to meet our internally mandated reinvestment rate of below 50% of operating cash flow. This slowed drilling pace in Q4 will translate to a significant increase in per-unit cash distribution. The third pillar is maintaining financial strength. We have maintained a goal to be at less than one times leverage prior to using substantial debt to make an acquisition. We project ending the year at 1.4 times. While we do not believe we currently operate in an area of high leverage, we are cognizant that more opportunities will be available to us if we were closer to a turn of leverage. So our goal remains in place. The point of this pillar is ultimate flexibility.

When the market gives us a chance to buy at attractive prices, we want our balance sheet to be an advantage, not a constraint. The fourth pillar is maximizing distributions to unitholders. This pillar drives all of our decisions. We have distributed nearly $7 to our unitholders since 2024. Very few public companies have yields at Mach’s level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a high amount of leverage that often can’t sustain once credit tightens or rates move up against them. Mach was built entirely different.

Our distributions and the cash returns we deliver are second to none, and they’re the result of the discipline behind our three pillars. Mach was established around a cash return model. We’ve said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash-flowing assets at seldom-heard-of prices by avoiding the tendency of the industry to look for growth through the drill bit. Our goal is to buy distressed assets at discounted prices that throw off cash. We were fortunate to pick the timing correctly and build a large producing base at bargain prices.

We continue to look for those type of assets, but it’s become more difficult as more capital is now chasing the same type of cash-flowing assets that we propose to buy and others are willing to pay premiums to our model. However, our steadfast approach to value has paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that’s HBP to hold our production flat by spending less than 50% of our operating cash flow. Therefore, in times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model.

Mach has a history of strong cash returns on capital invested and cash distributions. Over the past five years we have delivered an industry-leading CROCI averaging 35%. This is not only industry-leading but it’s also the top 1% of all public companies in the U.S. We also have distributed an industry-leading distribution yield of 15% since 2024 through Q3 2026. This performance was achieved through different pricing cycles, ranging from $94.23 per barrel in 2022 when we achieved a 53% CROCI to $64.81 per barrel in 2025 when our CROCI was 23%.

Since our inception we’ve never had a CROCI of less than 20%. We cannot find another company with such a strong record of cash returns. As we look to 2027, analysts’ expectations are somewhere between $2.00 and $2.50 per unit of CAD. In that scenario we are now trading at closer to a 20% yield versus our previous range of 10% to 15%. That gap sits in the unit price, not in the business, as yield is a ratio and only one side of it is in our control. What we generate and distribute is independent of where our units trade. We will distribute back as much cash as possible and let our unitholders decide if they would like to buy MNR.

For any investor with a long-term outlook, our units are a good purchase because we’re not in distress and trade outside of any normal yield equity. In other words, we will distribute the same amount of cash no matter where our unit price trades. We have now finished our natural gas drilling until we see some price recovery. The last of seven Mako Shale wells were drilled in September. We have one Oswego rig running that will increase to two Oswego-style rigs running in 2027 along with the completion of the seven Mako Shale wells in Q2 and Q3 of 2027. This program fits the profile of being less than 50% of operating cash flow while focusing on oil drilling. However, as you know, we can adjust our schedule very quickly if we see other opportunities that have potentially higher rates of return.

We continue to have high expectations for the natural gas market. We see natural gas demand increasing nearly 15 Bcf a day in 2028, with 2027 being a transition time from the loose market today to an adjusted world LNG base price as demand arrives. We expect the San Juan over the next five years to have additional takeaway capacity. These outlets will be installed to get to the premium gas markets of Arizona and the Pacific Coast LNG markets. We currently have a gas delivery agreement in place through 2030 that hedges approximately 60% of our San Juan natural gas.

By the time the contract expires in 2030, we will have strategic optionality for our 350 million cubic feet of gas that can be held flat by drilling only five net wells per year. If we choose to increase activity to 10 net wells per year, we could grow Mach net production to more than 500 million cubic feet a day. This is the benefit of buying low-decline cash-flowing assets that also have fantastic upside potential. The Mako Shale has potential to dominate the Mach story in years to come.

With regard to oil, we plan to increase by one rig in 2027 to maximize rates of return while staying under our 50% reinvestment rate. The current environment bodes much better for oil reinvestment than natural gas. We have many years of inventory left to focus on oil drilling if that is where the returns remain. Our decision to add oil reserves at a time when the oil market was in turmoil has put us in a good position to shift capital where returns are best.

We have built a company that can do well in any environment. We can sit around and wring our hands over our unit price, or we can choose to be comforted by knowing our yield is safe. I choose the latter. The unit price will ultimately take care of itself. I’ll now turn the call over to Kevin to discuss the financial results.

Kevin White (Chief Financial Officer)

Thanks, Tom. For the quarter, our production of 147,000 BOE per day was 15% oil, 69% natural gas, and 16% NGLs. Our average realized prices were $84.00 per barrel of oil, $2.17 per Mcf of gas, and $30.02 per barrel of NGLs. Over $360 million of total oil and gas revenues. The relative contribution for oil was 49%, 34% for gas, and 17% for NGLs. On the operating expense side, lease operating expense was $88 million for the quarter, or $6.49 per BOE. Cash G&A was $6 million. We ended the quarter with $31 million in cash and $250 million of availability under the credit facility.

Total revenues, including our hedges and midstream activities, totaled $319 million, adjusted EBITDA of $183 million, and $165 million of operating cash flow. Development CapEx for the quarter was $126 million, which was 77% of the operating cash flow. Year to date, our development CapEx is 59% of our operating cash flow. In the quarter, we generated $38 million of cash available for distribution, resulting in a distribution of $0.22 per unit, which will be paid on November 30 to holders of record on November 16.

With that quick overview, Melissa, I’ll turn the call back to you to open the line for questions.

OPERATOR

Thank you. If you’d like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you’d like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from the line of Neil Dingman with William Blair. Please proceed with your question.

Neil Dingman (Analyst)

Morning, Tom, and the rest of the team. Tom, I appreciate your distribution comments; they’re well taken. My first question is really on your continued development program. Specifically, I was wondering, will the Oswego continue to make up most of the activity next year, or are there potentially other oily plays you would add? And then, secondly, I would assume it does seem like you have more than ample Oswego inventory for this continuous program.

Tom Ward (Chief Executive Officer)

Yes. To the latter part, yes. We have a tremendous amount of Oswego locations left to be drilled. That is our primary target for oil. We have two rigs slated to work in the Oswego with other Oswego-type or high rate of return oil wells to be drilled. Some of those could be in Western Anadarko and the Red Fork. They could be Clear Fork wells in Texas. We might look at some oil locations in New Mexico. We have a very wide and broad and deep inventory of locations to choose from.

And so once you get down to where you only have one or two rigs running, we’ll keep one rig in the Oswego constant and have another rig that comes in and out of the Oswego as we see other areas that can compete with those types of returns. But it is difficult to beat the Oswego returns just because of how little we spend. We look at basis hedges. We put some on in the San Juan earlier this year. That’s kind of one way. You remember whenever we bought ICAV we already had a marketing arrangement in place that we just bought a stream of cash flow from the BP and ICAV had a long-term marketing agreement that covers about 60% of our volumes through 2030. So it really opens up perfectly for us that we become unhedged and bought ICAV. When we bought that, we only paid for that stream of cash flow.

And so at about the time that you’re going to have a pipe go more than likely west through Phoenix and around to the Baja California to LNG markets, you’re going to see a tremendous amount of uplift in the ability to market San Juan gas. So that particular transaction around ICAV just gave us a tremendous amount of marketing ability in the future. And keep in mind that there continue to be talks of data centers in and around the San Juan. It has tremendous water assets, it has a lot of land and if that comes to fruition, it also would take away some of the restriction around the San Juan basis.

So I’m pretty comfortable in the San Juan over the longer term and we didn’t pay for any of the upside anyway. So for us to sit and wait and to harvest that when prices do change is a fairly easy decision today. It’s the difference between where I believe gas prices are in the winter of 26, 27, which could go dramatically, even lower, to where prices could be in 28 and beyond is really the opportunity around gas companies. And that’s why you see the disconnect in sales packages to be very difficult for someone to buy at today’s strip when there’s a belief that things are much better in just a few years.

So, and in the Mid-Con, you know that we just have a tremendous amount of takeaway capacity. So there’s no restrictions. We don’t even need data centers here to be able to get gas out. So that’s the difference between the two.

OPERATOR

Thank you. Our next question comes online of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade (Analyst)

Yes, good morning Tom to you and Kevin and the rest of the Mach team there. Tom, I want to ask about the 4Q distribution. So it looks like with capex going down and oil prices, I mean we’ve got a couple months left to see but still looking strong. It looks like you guys are set up for, and I think you mentioned this in prepared remarks that you’re expecting a bigger 4Q distribution. My question is do you consider a lower distribution 4Q as an alternative versus at-the-market shares as a route to delevering or to you are those just separate buckets and you’re going to.

And they’re not alternatives.

Tom Ward (Chief Executive Officer)

I think I’ll let Kevin answer what he believes on. I look at them as separate buckets.

Kevin White (Chief Financial Officer)

Yeah, yeah, the same. The same. Charles, I don’t think we would use any part of the distribution in the fourth quarter for either debt reduction or unit repurchases. Either one.

Charles Meade (Analyst)

Got it. Okay.

Tom Ward (Chief Executive Officer)

I don’t see us, Charles, as being over-levered, especially in the near term because there’s really nothing we can buy that requires us to be down to a point that we need to use debt. So I mean I still would love to find an asset that was accretive to our cash available for distribution and use equity around an acquisition as a way to lower the debt levels. Those just really aren’t coming around and we continue to look but there’s just not many around today to be able to do that.

Charles Meade (Analyst)

Got it. And then Tom, if we could go back to some of your previous answer and this is around just elaborating on your options for oil drilling or oil-weighted drilling. Aside from the Oswego, you mentioned the Red Fork in the Mid-Con, you mentioned the Clear Fork in the Permian and I think you said which would be new for me, that there’s maybe some liquids-weighted opportunities in the San Juan. So could you maybe pick up on that last one if there’s any opportunities that are more liquid-rich than the San Juan and also just if that’s the three other options if there’s anything else.

Tom Ward (Chief Executive Officer)

Yeah, I wasn’t referring to San Juan. Enduring has all that tied up for liquids. I was just thinking in the Permian, New Mexico where we have a Lake Ridge, we picked that up mainly through the Sabinal acquisition. Scattered amounts of acreage around that have, in every acquisition you can find a few locations that have high rates of return.

Charles Meade (Analyst)

So the point is it’s New Mexico Permian, not New Mexico San Juan. Right. Got it. That’s it for me. Thank you.

Tom Ward (Chief Executive Officer)

Thank you, Charles.

OPERATOR

Thank you. Our next question comes from line of Derek Whitfield with Texas Capital. Please proceed with your question.

Derek Whitfield (Analyst)

Good morning Tom and team and thanks for taking my questions. Tom, I wanted to start first with your 2027 guidance. While I realize you’re not providing CAD guidance and commodity prices are subject to change, we are back into a yield of over 20% at current prices. Based on your guidance and based on the curves to kind of put a firm point on it for the benefit of shareholders. Is that similar to what you’re seeing on your dashboard A and then B, you guys are committed to 100% payout of CAD? Just want to be clear on those two points.

Tom Ward (Chief Executive Officer)

I’ll say yes, that in my prepared remarks I’m using you guys and agreeing with you that somewhere we have projected between 2 and 250 of CAD next year. Looking at what you project, we’re not giving guidance on that. But the other, it’s a board decision. My personal preference is until I feel a need to be paying down debt, I prefer to wait around a little bit for gas prices to perk up. And it’s my, it’s always my first desire to pay back all the CAD to unitholders and then let unitholders decide what to do with that.

That’s the way I prefer to run this. And so that’s as strong of an answer as I can give you.

Derek Whitfield (Analyst)

Appreciate that. And then on my follow up I wanted to come back just onto what’s embedded in guidance for 2027. Could you speak to kind of two things just on the activity inflation front, what do you have assumed for capex? And then secondarily given that medium term, near to medium term-ish constructive nature on natural gas, how are you thinking about the seven DUCs that are in the San Juan?

Tom Ward (Chief Executive Officer)

We are seeing inflation so far in diesel, bits and casing, thank you. Yeah, so those three are, they’re up dramatically quarter over quarter so maybe 30 to 50%. So we increased our Oswego drilling AFE by 11% for 2027. That, you know, we’re not seeing a reduction in pricing. So we assume you might be getting some sand increase soon that might have to go up a little bit more. But the rates of return, if you keep anywhere near the $70 range or so, are still extremely good around our oil drilling.

So it wouldn’t really affect us there. It might, you know, if prices dramatically reduced, we might have to cut back our drilling program just from an operating cash flow standpoint. But other than we do keep 50% hedged as you know. So we have a fairly good view into the next year and that still gives us a lot of opportunity if prices were to change to the upside. So I like having exposure to higher prices. I think that in both oil and natural gas there’s just as much potential to be higher instead of just looking at it from a viewpoint that things are only going to be lower from here.

Derek Whitfield (Analyst)

And Tom, just quickly, just again. Oh, San Juan

Tom Ward (Chief Executive Officer)

DUCs. So, yeah, sorry, I forgot about the San Juan DUCs. So the San Juan DUCs are in our model. They have a very, you know, once you take away the capital for drilling, it’s hard not to complete a well and have a rate of return that’s comparative to even our oil drilling. So they are in line right now. If natural gas prices were to fall tremendously, maybe they don’t get completed, but more than likely we’ll be looking forward into the 27, 28 winter and projecting that we need to be bringing those wells online.

Derek Whitfield (Analyst)

Fantastic. Really appreciate it. Thanks, guys.

Tom Ward (Chief Executive Officer)

Thank you.

OPERATOR

Thank you. Our next question comes from line of Michael Schaller with Stevens Inc. Please proceed with your question.

Michael Schaller (Analyst)

Morning, Tom. Morning, Kevin. Want to follow up on 27. Just kind of high level. You’ve given full year guidance. It sounds like oil price stays flat throughout the year. And then should we anticipate gas declines first half and then grows second half if you do complete the Mancos wells?

Tom Ward (Chief Executive Officer)

Yeah, I mean oil could be slightly higher year over year, but I mean in all things we look at, it’s just kind of keeping our production basically flat, either up or down below somewhere in plus or minus 5%. So I think that’s the way to look at it. But yes, it’s difficult with one or two rigs running to grow oil production dramatically offsetting the declines that we have. And natural gas, it could decline, just the way I would think of it is oil goes up in single digits and gas goes down in single digits.

Michael Schaller (Analyst)

Okay, got it. And then wanted to ask on your slide 24, you look back at your 25 drilling program, you give the rates of return. I thought it was interesting, the rates of return for the programs all look very good. It looks like there’s quite a bit of variability in the Oswego. You’ve got several wells that are kind of off the charts on the high end of the returns and then you’ve got some that are at the very low end as well. Just wondering if there’s anything you’ve learned about the play that helps you avoid the low end.

Or is that just the variability you have to live with?

Tom Ward (Chief Executive Officer)

Yeah, that’s why nobody else does that, because everyone has the same look, except for they don’t go as high with the wells on the left. It’s just every play that you draw has variability. And I’d say Peyto does it. So I copied this from Peyto because they do it every year. I just think it’s very rare for a company to show every well they drill, because we drill bad wells and then we drill really good wells, and it ultimately ends up that you try to find somewhere in the 20% to 30% rates of return that can really move the company forward.

And that’s what we look for. We’ve been able to beat that. And that’s, you know, what’s really rare about our company is that we paid zero for future leasehold. We bought PDP under a PDP PV-10. So we bought a cash flow stream and we paid nothing for the upside. And yet we’ve spent a billion and a half dollars since inception, or since, you know, drilling wells on land that was valued as being worthless. So that’s my take. And then if you even look at outside parties, I think we have a slide on that that was done last year, that our results are in the top quartile—well, heck, in the top 5%—of everyone that’s drilling wells, both in gas and oil. So that’s what’s kind of interesting. I think that has to do with having a very small drilling program where you get to pick locations one at a time instead of having this just kind of, we’re going to run 10 rigs out here in the Permian and they’re all going to be exactly alike.

They’re just not. And you end up, your drilling program takes over your life and then it takes away from being able to keep your LOE down. So all of this is trying to run a company that is not so focused on drilling but that can pick out very high rates of return drilling from a massive land scale. And that’s the secret. Thank you.

OPERATOR

Thank you. Our next question comes from line of Jeff Grant with Northland Capital Markets. Please proceed with your question.

Jeff Grant (Analyst)

Hey, good morning, Tom. Wanted to circle back on the leverage front. Just wanted to confirm here it sounds like there’s not a tremendous urgency to get the leverage down through any proactive measures until, I guess, the M&A market looks a little more enticing. I guess A, wanted to confirm that, and B, is it fair that, like, in a world where M&A is more interesting, maybe you can just touch on the main avenues you see to get leverage down to where you guys can be a little bit more on the offense, if you will.

Tom Ward (Chief Executive Officer)

Yeah. If I thought there were just a lot of opportunities to go and put together assets at discounts to PDP PV-10, or in a cycle where things are falling apart and we could put much-needed to work, I’d be more aggressive at trying to get leverage down so we can participate. But as I look forward, it just doesn’t appear to be that way. We do—we’re cognizant that we’re higher than we want to be. I think, you know, just in 2027 alone, in natural gas prices moving somewhere above $3, our leverage kind of takes care of itself.

So whenever I look out to 2028 and see what I believe will be a market that goes on the natural gas front that brings us closer to a world price—between the TTF and JKM, the Japan Korea Marker, and LNG in the U.S. becoming more of a worldwide—I think gas becomes more of a worldwide asset, that prices will move up. And that’s if—a lot of ifs in this. But it just makes me not too worried. Yes, we have higher leverage than I want to, but I think it can be managed in the next year.

And so it doesn’t make us in any hurry to make this something that we would go issue equities or that we need to take away from our distributions.

Jeff Grant (Analyst)

Got it. That’s helpful. Details for my follow-up on slide 15. With some of the efficiencies in the Oswego kind of trending up to the last few years, can you just kind of touch on more recent results? Are those kind of tracking in line with some of the recent improvements? Is there more to go, or just any kind of updates relative to that slide would be interesting.

Tom Ward (Chief Executive Officer)

Yeah, it’s mainly just drilling longer laterals. So when we first started drilling in the Oswego, we focused on one-mile laterals, not knowing really the nature of the reservoir. And over time we’ve been able to have land situations where we can drill longer laterals, and that’s just made us more efficient.

Jeff Grant (Analyst)

Gotcha. Appreciate the time, guys. Thank you.

Tom Ward (Chief Executive Officer)

Thank you.

OPERATOR

Thank you. Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.

John Freeman (Analyst)

Thank you. Good morning, Tom. On the comments that you made on the M&A market, you’ve got pretty wide bid-ask spreads, and there’s a lot more parties that are kind of looking at some of the kind of asset profiles that you guys have targeted all along. Just given, like, the massive sort of acreage position that you’ve got, does it actually cause you all to maybe consider, you know, divesting some assets if the market’s just, you know, pretty hot for certain assets that maybe right now, just given the big position you all got, don’t compete for capital?

Is that something y’all consider?

Tom Ward (Chief Executive Officer)

Yeah, not too often. We have sold a little bit of acreage in the past, but more than likely we trade. There’s usually trades to be made around our positions with others that improves the positions we have and helps others drill their wells. That’s what we mainly do in land. The other thing you don’t want to do is be giving away your future drilling. Even in western Oklahoma now, there’s some formations that are being drilled—new formations—that are looking quite good that, if we would have sold those in the past, we wouldn’t have known.

We want to keep our inventory. That’s basically it. We’re no real need to be bringing in additional cash. We already have a tremendous amount going forward. But I like the idea of having locations in your back pocket so whenever oil prices change or gas prices change, you can move a rig around and get those high rates of return. So it’s not anything we really focus on.

John Freeman (Analyst)

Understood. And then my follow-up question. Appreciate all the detailed numbers and outlook on 27. Just to make sure we sort of capture maybe if there’s any fluctuations in the capital next year. Just at a high level, should we just think of it as you’ve got, like, the steady two-rig program in Oklahoma, and then you’ve just got those macOS completions in 2Q and 3Q? So from a capital standpoint, does that kind of indicate, like, 1Q and 4Q are kind of lower and 2Q and 3Q kind of bump up in terms of capital, just at a high level?

Tom Ward (Chief Executive Officer)

That’s correct. And not necessarily Oklahoma, but two oil rigs, and one gas completion—drilling no new gas wells. Assuming our operating cash flow doesn’t change dramatically.

OPERATOR

Thank you, ladies and gentlemen. That concludes our question and answer session and we’ll conclude our call today. We thank you for your interest and participation. You may now disconnect your lines.

Disclaimer: This transcript is provided for informational purposes only. While we strive for accuracy, there may be errors or omissions in this automated transcription. For official company statements and financial information, please refer to the company’s SEC filings and official press releases. Corporate participants’ and analysts’ statements reflect their views as of the date of this call and are subject to change without notice.