Mach Natural Resources - Earnings Call - Q4 2024

Executive Summary

• Q4 2024 revenue was $235M, net income $37M, and Adjusted EBITDA $162M; production averaged 86.7 Mboe/d with LOE at $6.17/Boe. Distributions of $0.50/unit for Q4 were declared for payment on March 13, 2025.
• Management reaffirmed the operational 2025 outlook and lowered the interest expense midpoint by $22M, improving 2025 free cash flow; pro forma net debt/Adjusted EBITDA moved to 0.8x after equity proceeds and refinancing.
• Q4 saw continued integration of two bolt-on acquisitions and entry into a new $750M revolving credit facility, with term loan repayment and RBL draws repositioning the capital structure for flexibility.
• Sequentially, revenue declined vs Q3 and per-unit distribution fell, largely due to principal amortization and sharing with new equity purchasers; interest expense decreased to $24M as refinancing benefits began to accrue.
• Consensus (S&P Global) estimates data was unavailable; therefore, vs-estimates comparisons are not provided.

What Went Well and What Went Wrong

What Went Well

• Cost discipline and operational execution: LOE of $6.17/Boe and G&P of $3.36/Boe; production 86.7 Mboe/d with 11 gross wells spud and 10 brought online in Q4.
• Capital structure enhancement and FCF uplift: New $750M RBL, term loan repayment, and $230M equity offering reduced pro forma net debt/EBITDA to 0.8x and lowered the 2025 interest expense midpoint by $22M.
• Strategic clarity around distributions and reinvestment: “We maintain a reinvestment rate of less than 50% of our operating cash flow... We target peer-leading variable distributions,” and midstream assets contributed $78M of EBITDA in 2024, underscoring integrated returns.

What Went Wrong

• Sequential revenue and per-unit distribution compression: Revenue fell to $235M from $256M in Q3; Q4 distribution was $0.50/unit vs $0.60 in Q3, driven by principal amortization and sharing with new equity purchasers.
• LOE up vs Q3: LOE per Boe rose to $6.17/Boe from $5.85/Boe, with CEO indicating BOE expense should be “basically flat” in 2025.
• Natural gas price sensitivity remains: Despite stronger Q4 realized natural gas pricing ($2.31/Mcf), management highlighted prior-year lows and continued macro exposure; leaving more liquids in gas stream is elective but keeps mix gas-heavy when economics favor it.

Transcript

Operator (participant)

Greetings and welcome to the Mach Natural Resources fourth quarter and full year 2024 earnings results conference call. At this time, all participants are in listen-only mode. If any of you require operator assistance, please press star zero on your telephone keypad. A question-and-answer session will follow the formal presentation. You may press star one at any time to be placed into the question queue. As a reminder, this conference is being recorded. It is now my pleasure to turn the call over to Chief Executive Officer and Director Tom Ward. Please go ahead, sir.

Tom Ward (CEO)

Thank you, Kevin. Welcome to Mach Natural Resources fourth quarter earnings update. Each quarter, it's important to reiterate the company's four strategic pillars. These are, number one, maintain financial strength. Our goal is to have a long-term debt/EBITDA ratio of one times or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Two, discipline execution. We acquire only cash-flowing assets at a discount to PDP, PV10 that are accretive to our distribution. Three, disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. By keeping our reinvestment rate low, we optimize our distribution to unit holders. Four, maximizing cash distributions. We target peer-leading variable distributions. This pillar drives all decisions. I'd like to add additional color to each of these four pillars. Disciplined execution.

Our strategy, since the founding of the company in 2017, has been to purchase cash-flowing assets at bargain prices while paying nothing for associated acreage and future drilling, and very little to nothing for the associated infrastructure and midstream assets. Our company was built during a time of distress in our industry. We made our first acquisition in early 2018 and then followed that with 19 additional acquisitions. We accumulated over 1 million acres of land that is held by production. We have ownership in four midstream gathering and processing facilities and significant other infrastructure. We purchased these facilities for $65 million, and these assets contributed $78 million of EBITDA in 2024 alone. $17 million of this midstream EBITDA came from third parties, and the remainder from higher realized wellhead prices for our own production.

In every single one of our acquisitions, our best-in-class operating team has reduced LOE by 25-35% from the previous owner's cost. Disciplined reinvestment rate. We now have the distinct advantage of choosing where to drill from hundreds of potential locations on the previously mentioned 1.1 million acres. In general, we look for opportunities to invest in projects with the potential to have at least 50% IRRs. In our presentation posted today on our website, we list all of the locations drilled in the Oswego and Wood Formations during 2024. In short, even during a year with exceptionally low natural gas prices, we achieved our goal. Natural gas prices have recently moved up, and that will result in more operating cash flow during 2025.

We plan to move in an additional rig in 2025 and still stay below our 50% reinvestment rate while adding high rate of return wells to our production. In 2025, we anticipate three rigs running. Continue to drill the Oswego Formation of Kingfisher County, where we've drilled more than 225 wells since 2021. The Mississippian and the Woodford Formations in the condensate window of the STACK and Ardmore Basin, where we incorporate locations from the last three acquisitions made, and the Deep Mississippian Formation in the Anadarko Basin. It is worth highlighting that out of the 45 wells drilled in our Oswego and Woodford drilling program, that greater than 35% achieved more than 100% rates of return. These were all drilled on lands that we paid zero for. We drill wells that are highly efficient.

For example, our Oswego DNC cost in 2024 averaged only $2.6 million or $202 per lateral foot. By keeping our costs low, we achieved medium payout periods of 15 months, assuming that flat $70 WTI and $3.50 Henry Hub. According to Enverus, this compares to 14 months in the Delaware and 15 months in the Midland Basins, where purchasing locations can cost more than $10 million each. All of these statistics add up to unmatched cash returns for our unit holders over the last five years and the next five years. We anticipate spending between $225-$240 million on drilling and completion plus workovers in 2025. With this expenditure, we anticipate holding our production basically flat, either up or down a few percentage points on a BOE basis. Maintain financial strength. We also watch our leverage very closely.

During the downturn starting in 2019, we adjusted our development CapEx from $101 million to only $28 million in 2020, $61 million in 2021, then $291 million in 2022 as prices rose. All the while, our EBITDA grew from $119 million to $719 million over the same period. We achieved this exceptional performance by being able to acquire cash-producing properties in a distressed environment due to our strong balance sheet. Mach also has peer-leading PDP decline and reinvestment rates. Our next 12-month PDP decline is projected to be 20%, while our reinvestment rate in 2024 was only 47%. Both of these statistics are number one in a group of 16 peer companies. We have exceptionally strong asset coverage with total proved coverage of 3.9 times, net debt enterprise value of 21%, and PDP PV10 to total debt of 3.3 times.

Our LOE averaged $6.17 per BOE in the fourth quarter of 2024, and our 2024 free cash flow was $8.43 per BOE. We're also starting 2025 with a net debt EBITDA at 0.8 times pro forma for our recent offering. Maximizing distributions. Management tries to understand risk and mitigate that risk where possible. We hedge 50% of our oil and natural gas on a rolling one-year basis and 25% during the second year. We also have a variable distribution that rises and falls with the changes in pricing. Each quarter, we are methodical to reinvest 50% of our operating cash flow, then receive our calculated cash available for distribution and send it home to unit holders. We've done this since our inception and do not plan to change our approach.

During this time, we have distributed back to our owners over $1 billion. When we hold our production flat by spending less than 50% of our operating cash flow, we are allowed to send back distributions to our unit holders. The best way to describe what we do is consistency. In all price environments, we maximize our distributions while maintaining a clean balance sheet. In times of lower pricing, we lower our CapEx, thus not having long-term contracts on capital expenditures. In doing so, we continue to have excellent cash returns on capital invested. Our CROCI five-year average from 2020 to 2024 is 32%. This was achieved through several commodity cycle fluctuations.

During 2024, we delivered total net production of 86.7 MBOE a day and reported net income and adjusted EBITDA of $185 million and $601 million, respectively. We also distributed $310 million or $3.20 per unit and attained a cash return on capital invested metric of 25%. Recently, we closed a bolt-on acquisition in the Ardmore Basin of approximately $30 million that will provide additional locations for us to drill this year. We repaid the company's term loan and lowered our net debt EBITDA to 0.8 times from 1.0 times. We then entered into a new revolving credit facility with an initial borrowing base of $750 million. We continue to have success buying assets in the mid-continent. Our latest successful acquisitions have been in the $100 million range.

In fact, we made 20 acquisitions and averaged just less than $100 million on each one. This approach is important as we can stay away from large, well-capitalized competitors to buy assets that are less expensive. We focus these acquisitions on not only acquiring PDP at less than PV10, but also acquiring land that one day will be drilled by us at no cost and no timeframe for expiration due to being held by production. This formula served us well. We also like buying crude oil anytime we move into the $60s or less and have a backward dated curve. We see the crude market moving through the inevitable one to two standard deviations both up and down and want to be ready with a strong balance sheet during times when pricing is at the bottom of a cycle.

We do not envision a longer-term down cycle in the vein of 2015 to 2020 and feel like it is a good time to lean in on a crude acquisition if we can find the right deal that fits our criteria for investing. However, we also do not stray away from our basic philosophy of needing an acquisition to be accretive to our distribution. We also will trade in natural gas if the opportunity arises at the correct price. In order for us to make a larger acquisition, say something north of $500 million, we need to find a partner who will be willing to take equity alongside of us.

We believe our time is coming when PE firms and small public companies will find our formula for cash returns attractive and want to be a part of a larger Mach. We welcome these opportunities as a way to grow our business while creating larger cash returns to our unit holders and having more float so that institutional investors can participate on a larger scale in our business. I feel that we will accomplish at least one of these types of transactions in 2025. Even if we do not make a meaningful acquisition, we will continue to replace our production through our drilling program and small acquisitions and deliver excellent returns to our unit holders.

In 2024, we ranked first out of all public upstream energy companies in distribution yield. We also ranked 10th in the total shareholder returns. We achieved these returns at a time of very low natural gas prices. In fact, 2024 had the lowest natural gas prices since the early 1990s. Our commodity mix on a revenue basis was weighted 59% oil, 21% natural gas, and 20% NGLs by revenue in 2024. However, as we move into 2025, we can see what happens in a higher natural gas environment with our volume by product being 54% natural gas, 23% NGLs, and 23% oil.

Therefore, in a $4 plus environment for natural gas, we're leaving all of our liquids in the gas stream and producing 77% of our production as natural gas. This increase in EBITDA allows us to have more operating cash flow, which enables us to add another rig in 2025 to have three rigs running versus the two we had in 2024. We remain focused on the price for our products and our reinvestment rate. The reinvestment rate drives our budget, not the IRR of the wells we drill. We feel confident we can continue to achieve high-return drilling results, but we will not move away from our core tenets of keeping the reinvestment rate low to maximize cash returns to unit holders.

If we are fortunate enough to add larger acquisitions, we'll be able to then monetize more of the hundreds of high internal rate of return projects we have waiting to be drilled on our 1.1 million acres of HBP land. This is why our focus remains on free cash flowing assets to acquire at prices that are accretive to our distribution. In closing, I want to reemphasize that we are an acquisition company. Our industry-leading cash returns have been made through opportunistic acquisitions. This is our primary lever of growth. Our expectation is to continue making acquisitions that are accretive to our distribution in 2025, just as we have over the last seven years in 20 deals. I'll now turn the call over to Kevin to discuss our financial results. Thanks, Tom.

For the fourth quarter, our production of 86.7 thousand BOE per day was 24% oil, 52% natural gas, and 24% NGLs. Our average realized prices were $70.06 per barrel of oil, $2.31 per MCF of gas, and $25.82 per barrel of NGLs. Our G&A stayed flat during the quarter at $8 million or around $1 per BOE. We ended the quarter with $106 million in cash, and our first lien term principal was $763 million. During the quarter, total revenues, including our hedges and midstream activities, totaled $235 million, adjusted EBITDA of $162 million, and $134 million of operating cash flow.

After CapEx of $60.5 million, we generated $81 million of free cash, which we used to pay our final principal amortization of roughly $20.6 million on the first lien term loan, and the remainder resulted in the $60 million or $0.50 per unit distribution for this quarter and was paid earlier this week. As Tom mentioned, we've closed on a new $750 million RBL made up of a syndicate of 10 banks. We're currently drawn around $500 million. With that, Kevin, I'll turn it back to you to open up the call for questions.

Operator (participant)

Certainly. With that, we are conducting a question and answer session, if you'd like to be placed into question queue, please press star one on your telephone keypad. We ask you, please ask one question, one follow-up, then return to the queue. One moment, please, while we pull for questions. Our first question is coming from Neal Dingmann from Truist Securities. Your line is now live.

Neal Dingmann (Managing Director)

Morning, Neal. Thanks for the time. Tom, sound pretty optimistic still on just the M&A environment. I'd love to hear gas, oil kind of still in the mid-time, kind of what were you telling your expectations also this year?

Tom Ward (CEO)

My expectations on gas and oil?

Neal Dingmann (Managing Director)

Just for, you know, we're seeing sort of the better, you think you might see some of the better deals this year.

Tom Ward (CEO)

Oh, yeah, or either gas or oil on better deals. Yeah, that's a good question. We kind of take what is delivered to us. So if we can make a deal on gas or oil that fits our criteria, we try to do it. I mentioned that I love buying oil in the 60s, so we've made a lot of money over the past several years buying low-priced oil, especially in a backward dated curve and letting that come to us over time. I just don't believe we're in a type of market over the next five or ten years that is going to consistently be down at these levels. I do like buying crude oil at these prices. We look at those deals, but we also look at natural gas.

If we can make a good natural gas acquisition that's accretive to our distribution, we'll do so. I guess if I had to pick one of the two right now, I think we would lean in on a crude oil deal. Got it. Secondly, as you pointed out, and I think justly so, you've got pretty notable infrastructure now that you've put together over the years. Is there, would you ever consider modifying that, just too valuable now to the development of your properties? Maybe just any comment you can make on the infrastructure and the value that you see behind that. Yeah, a lot of good would be to sell some of our infrastructure. I think they're pretty critical to our operations. I don't see any reason for us to be trying to get rid of them.

As we mentioned, every year that goes by, we produce more EBITDA than we paid for the whole system. They are valuable, but they're also valuable to us. We'd have to pay somebody else if we were to pass them on to them. I do not think so. I think we will plan to keep them.

Neal Dingmann (Managing Director)

Great value there. Thanks, Tom.

Tom Ward (CEO)

Thank you.

Operator (participant)

Thanks. Our next question today is coming from Charles Meade from Johnson Rice. Your line is now live.

Charles Meade (Research Analyst)

Good morning, Tom and Kevin.

Tom Ward (CEO)

Good morning.

Charles Meade (Research Analyst)

Tom, I wanted to ask, I guess, about the third rig. Can you tell us when it is going to come? I imagine how long it stays is really going to be a function of your reinvestment cap. When is it going to come? Is that going to be focused on the Anadarko Deep Mississippian that you talked about?

Tom Ward (CEO)

Yes. The third rig is coming just any day for a four-well program in the Oswego. Then that rig will leave and we will pick up another rig that starts the Deep Mississippian project in Western Anadarko and Western Oklahoma. It is really driven by reinvestment rate as prices have moved up, our operating cash flow has moved up. We are able to bring in a rig in the Oswego that allows us to stay closer to 50% reinvestment rate. That is going to be short term while we bring in a larger rig to drill the Deep Mississippian in Custer County.

Charles Meade (Research Analyst)

Got it. Yeah, it would make sense. You would need a bigger rig for Custer County than the Oswego and Kingfish. Second question, Tom, I really appreciate the comments you laid out on oil, but I am wondering if you could do the same for gas. I mean, it is not new this week or this month, but maybe this month. We are looking at backwardation of the gas curve for the first time in a long time with this big run we have had in natural gas prices. I wonder if you could tell us what you think the setup is there. Perhaps as a way of doing that, you said you like to buy oil assets when oil's in the 60s. Where do you like to buy gas assets?

Tom Ward (CEO)

Oh, I always liked to buy gas assets. I think long term, I'm no different than basically anyone else now that believes that natural gas is the fuel of the next 10 years that's going to have tremendous demand. Yeah, maybe in 2028 or so, you get the Qatar LNG coming on that might dampen natural gas prices some for a time. I think demand overall just is increasing. Anytime you buy something in Anadarko, you're going to get about 50% natural gas and another 25% or so in natural gas liquids, along with crude oil being basically 25%. Any deal we make is just by its very nature in the mid-con of a natural gas asset. We have done extremely well at buying cheap natural gas.

My belief is that we still could look towards a $5 curve this summer as we need to do refills, as we are going into refill season and need to be back at 3.8 TCF or so by the end of October. I do not know, we will have plenty of times of moving up and down and around with gas prices, but I still think there could be a dollar move here in the summer strip.

Charles Meade (Research Analyst)

Thank you for the thoughts, Tom.

Tom Ward (CEO)

Bye.

Operator (participant)

Thank you. Next question is coming from Michael Scialla from Stifel. Your line is now live.

Michael Scialla (Managing Director)

Good morning, guys. Tom, I wanted to see if you could talk a little bit more about the recent bolt-on you did. You mentioned the nine PUDs. Any probable locations with that? I'm curious, you bought typically from distressed sellers. Looks like you paid well below PV10 value here. Could you characterize the seller situation here, why they were willing to let it go for the price that they did?

Tom Ward (CEO)

They were not as distressed as most of the sellers we've had over time because they were just individuals who went out and drilled a few wells and were able then to sell those at basically PDP, PV10 to us and made a lot of money. They drilled good wells. They sold us the wells that they drilled, and we paid a fair price for those. We inherited the pods that they'd proven. There are not any probable locations because it was drilled in an area and they're drilling and others have proved it. The nine locations we drill throughout the rest of this year and the next year are going to be pods already. It is a good area to drill in with good rates of return.

In fact, just by the very nature of being in our drilling program, we expect to have 50% rates of return.

Michael Scialla (Managing Director)

Sounds good. I wanted to ask on the fourth quarter distribution. It was a little bit below on a percentage of cash available for distribution than third quarter. Can you talk about the factors that went into that decision?

Kevin White (CFO)

Yeah, Michael, I am not sure if you are looking at the table itself. The cash available for distribution came in at a little above $80 million, but that is after interest expense, but before we made our principal amortization. The principal amortization took a little over $20 million away from that $81 million. Net after the principal payment, we did send out all the cash that we generated for the quarter. The per unit number was a little bit lower because the per unit distribution was shared with the equity purchasers that occurred in February.

Tom Ward (CEO)

Our cash available for distribution, when we send that out, is fairly mechanical and keeps basically everyone happy, both equity and our debt holders.

Michael Scialla (Managing Director)

It is really all due to the recapitalization of the balance sheet during the quarter.

Kevin White (CFO)

If you were looking at the per unit number.

Michael Scialla (Managing Director)

Yep. Perfect. Thank you.

Kevin White (CFO)

You bet.

Operator (participant)

Thank you. Next question is coming from Derrick Whitfield from Texas Capital. Your line is now live.

Derrick Whitfield (Managing Director)

Good morning, all. Thanks for your time.

Tom Ward (CEO)

Sure.

Derrick Whitfield (Managing Director)

Wanted to focus on your 2024 drilling program results with my first question. As you guys look back on the 2024 program, are you seeing opportunities for the Woodford to close the gap versus the Oswego in returns from a DNC efficiency or optimization perspective?

Tom Ward (CEO)

We've been pretty efficient. I think both of those zones are basically doing what we've asked them to do. The Oswego program is just much more mature. To me, it's an easier program to hit our rate of return just because it's fairly simple to drill and, or I guess, not as complex to drill as some of the deeper Woodford. Just the amount of communication that we have in between wells tends to be a little less. I don't think it really necessarily closes the gap. We've already cut the drilling cost by nearly $2 million a well from when the prior operator had it.

I will never say never about our team and their efficiencies, but it kind of looks like I would not expect a different outcome in 2025 versus 2024. Therefore, I mean, what can happen is that an Ardmore Basin well or a Deep Mississippian well can have higher rates of return than a condensate well in the condensate window. Therefore, after the next couple of wells that are drilled in the condensate window, we will be moving that rig to the Ardmore Basin.

Derrick Whitfield (Managing Director)

Yep, that makes sense. Maybe regarding M&A, could you more broadly speak to the competitive landscape in the mid-con as it appears the privates like Validus are most responsible for the competitive environment we are seeing today? Also, just maybe leaning in on where you were just now on the organic leasing opportunities you are seeing in the deepness.

Tom Ward (CEO)

Yeah, the mid-con has become a very popular place. Our rig count has gone up over the last year. The amount of interest in buying assets has gone up. Well-capitalized companies are moving in to purchase assets. We have never really been great at buying very large packages other than the Paloma one was the one exception for us. The amount of competition for those types of assets continues to be fairly strong. I see us having the niche still of buying $100 million type assets where others are really looking and continue to look for free cash flowing assets that might not have as much of the drilling upside. We really do not need that because we have so many opportunities ourselves inside of our existing acreage.

I mean, what we're really focusing on is trying to grow our operating cash flow and then using 50% of that to increase our drilling budget into high rate of return drilling that we already have captured inside our existing acreage. Tom, just on the organic leasing opportunities you guys are seeing across the basin, maybe could you elaborate on that? I mean, we already have so much acreage that's held by production. Across the deep Anadarko and the deeper condensate window, we have over 65,000 acres currently. We do not have to lease very much. I think our total budget for leasing this year is around $30 million for 2025. That is focused more in the deeper areas, as you mentioned. The Cherokee also, both the Cherokee Shale and the Red Fork Sands have been areas we've been watching.

Most of our leasing budget is places that we already own acreage. We propose a well, and then we buy the rest of the unit as it is being put together.

Derrick Whitfield (Managing Director)

Very helpful. Thanks for your time.

Tom Ward (CEO)

You bet.

Operator (participant)

Thank you. Next question today is coming from John Freeman from Raymond James. Your line is now live.

John Freeman (Managing Director)

Good morning, guys. Hey, John. Just following up on that last comment, Tom, because it looks like on a year-over-year basis, the midstream and land expenditures as a percentage of the total budget is doubling, both on a percentage of the total and on a dollar amount. Did you just say that the $30 million of that midstream and land that you all lump together, the $35 million-$40 million range you gave for the year, did you say $30 million of that is for land?

Tom Ward (CEO)

Yeah, I think that's our budget for land, isn't it? $30 million.

John Freeman (Managing Director)

Land and midstream.

Tom Ward (CEO)

Okay. Yeah, that does include both. I'm sorry, John.

John Freeman (Managing Director)

The midstream stays virtually the same, I think, as in prior years. The biggest part of the change is for leasing activity. Again, as Tom mentioned, the majority of that just comes as a byproduct of a larger drilling program.

Tom Ward (CEO)

John, as you think too, as you move into another rig running, that does have just more locations that we add acreage on.

John Freeman (Managing Director)

Okay. Yeah, that makes sense. You also talked about just the increased activity that we're seeing in the Anadarko. I know just Oklahoma overall has seen the biggest increase in drilling activity of any region in the country the last several months and just sits behind only the Permian at this point. What sort of impact, if any, does sort of the non-op portion of your budget see this year versus last year's budget?

Tom Ward (CEO)

Our non-op budget is usually fairly small. We elect out of most of the non-ops that are proposed to us. We are participating in a couple of deep gas wells that are being drilled now by Continental. In general, I think our non-op budget stays fairly consistently low.

John Freeman (Managing Director)

Got it. Thanks. Nice quarter, guys.

Tom Ward (CEO)

Thank you.

Operator (participant)

Thank you. Next question is coming from Selman Akyol from Stifel. Your line is now live.

Tim O'Toole (Associate VP)

Hi, good morning, guys. This is Tim on for Salman. I just wanted to touch on, in the prepared comments, you mentioned kind of leaving more liquids in the gas stream given where natural gas prices are. Just curious, are you guys able to make that election across your footprint, or is it only where you guys kind of have the infrastructure?

Tom Ward (CEO)

No, we can make that election basically across our production. Okay. Got it. Would you expect that to have natural gas production guidance to trend towards the high end and NGLs maybe trend a little lower or any kind of comments you can provide on that? It stays in the range. Yeah. Yep. Sorry, the answer is stays in our range. Okay. Got it. Last one for me, BOE expense has kind of been ticking up in 2024, and I believe that was partially due to the Paloma wells. Just curious on kind of the cadence we should look for in 2025, whether it is kind of a flattening or kind of a continuous kind of uptick. Yeah, I think it's basically flat.

Tim O'Toole (Associate VP)

Okay. Perfect. Thank you, guys, for the time.

Tom Ward (CEO)

Yes.

Operator (participant)

Thank you. We've reached the end of our question and answer session. I'd like to turn the floor back over for any further closing comments.

Tom Ward (CEO)

Kevin, thank you. Thanks to everyone for joining. We look forward to our next call in a quarter. Thanks.

Operator (participant)

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.