Well, thank you, and thanks for having me, and thank you all for showing up to hear a little bit more about Flowco. I'd love to maybe spend about 15 minutes telling you a little bit about who we are, how we got to where we are, and as importantly, what we plan to build, and save about 10, 15 minutes for some discussion on stage and maybe some Q&A from the audience. But maybe as a highlight, I won't make you read our legal disclaimer. We are a pure play production optimization and artificial lift company. All we focus on is the production phase of an oil and gas well. We are not exposed to drilling expenses or fracking expenses, okay? So when an oil company turns on a well, that's when our revenue line starts. We lead the way in every one of our products. We have a number one market position in everything we do, and as I said, virtually all of what we do is onshore U.S. We have a highly visible recurring revenue stream, which we can touch on as we go through our products, and we have a who's who of customers, ranging from large majors to large independents and also on down to small family-owned and private equity-backed oil companies. Roughly 1,300 employees, operating in every major basin in the U.S. We have a vertically integrated model, where we manufacture everything that we either sell or rent. We're headquartered in Houston, have over 200 customers, and you can see the numbers on the right. I think what the key takeaway is that over the last several years, and even if you go back further through cycles, we've been able to continue to grow our business, and generate very high and very attractive rates of return on invested capital, which we think is a differentiator in the OFS space, so we are organized in two divisions, and maybe rewinding a bit to the formation of the business. We merged three companies together, roughly eighteen months ago, to create what is today Flowco. You'll see the brand names at the bottom. These were all highly successful, either founder-owned or private equity-backed, oil field service companies that had one key thing in common, which is the focus on helping oil companies manage their production. Not helping them drill or complete new wells, but rather being their chosen partner to help them manage production for the life of the well. We took these businesses, put them together, and did so for that exact industrial logic. The oil company clientele that we have in the United States likes the specialty that we bring to the table. They like the fact that we have organized what were multiple brand names into two operating divisions. On the left, you have our Production Solutions segment. This is roughly 60% of our business. We manufacture and rent, and also sell artificial lift systems to help oil companies flow their fluids in a more efficient way to the surface. We'll touch on the various methods of that as we go through. On the natural gas technology side, we are the leaders in methane abatement. What does that mean? We actually capture methane vapors that are a byproduct of oil and gas production and allow oil companies to monetize molecules that would otherwise be vented or flared to the atmosphere, so a very clear environmental benefit to an oil company, but more importantly, a very compelling commercial proposition to an oil company looking to add to their P&L with what was previously considered a waste product. We have over 4,400 active rental systems spread across every active shale basin in the U.S. I said earlier, roughly 200 customers, 43 field locations, and six manufacturing centers of excellence. Very stable, very loyal workforce, which we're proud to call part of Flowco. I think as you look at our company and you compare it to the rest of the oilfield service sector, the production focus cannot be overemphasized. This page attempts to boil down into a couple of statistics, really what causes us to stand apart. And if you look at the bottom left-hand graph on this page, you can see that producer operating expenses are projected to grow at roughly a 4% CAGR for the next several years. And this is in the face of what the market is telling us is a flattening production profile. So how does that happen? Why do we think that production will be flat, while the expenditures on maintaining that production will actually grow? It has everything to do with the fact that this industry has to run hard to stay flat, right? The decline curve never sleeps. Oil companies are continually bringing on new production to replace production that is declining. Therefore, you have more wellbores that are with us for decades at a time, that need to be managed over the life of that well. That's why, very simply, OpEx continues to rise as production flattens. The beauty of our business model is that we are there for the life of the well. We have a suite of technologies that we can offer an oil company early, as the well is turned on. As the well matures, that operator has to switch to a different form of artificial lift to maximize the production out of that wellbore, and we're there for that changeover. As the life of the well is into its second decade, we're there for kind of the final form of lift as well. The beauty of all of this is, if you're there early, you're there as an incumbent, you're allowed to be first in line in the customer's office to talk about the new solution as the well matures. Our vapor recovery systems are there for the life of the well pad, and they have a similar characteristic of downsizing as well pads mature from large to medium to small, to more optimally produce hydrocarbons from the well pad. At a really high level, just to orient you on our artificial lift business, we participate in a roughly $15 billion market globally. Roughly half of that is in the United States, and of the half of the $7 billion-$8 billion market in the United States, we participate today in roughly half of that. So our total addressable market in the United States today approaches $3.5 billion. Again, we lead in every one of these market niches with number one shares. And what you hear from us is an organic growth strategy, and a demonstrated ability to grow with this technology at the top of the list here, called high-pressure gas lift, displacing legacy forms of artificial lift. There are two ways you can lift a well at the beginning of its life: you can either inject natural gas downhole to produce fluid, or you can deploy a mechanical device downhole and connect it electrically to the surface to mechanically lift the well. The latter is an ESP, the former is a high-pressure gas lift system. We invented the technique of high-pressure gas lift roughly six years ago, and from one unit and one customer, we have grown to roughly 800 units and roughly 60 customers across all major shale basins. That's really been the driver of the growth of our artificial lift business for the last several years. We have taken, from scratch, roughly 15% of the market from the legacy forms of artificial lift, mainly ESPs. So we think there's room to grow there. It's early innings, and that's part of our growth CapEx plan that we went through in our IPO roadshow. We've continued to reaffirm that as we've reported our first couple of quarters post-IPO. That growth market share gain is still very much intact, even in today's more challenging environment that we find ourselves in. When you look at the artificial lift market in total, the sectors that we're exposed to are growing more quickly than the legacy forms of lift that we do not participate in. They all share the common theme of taking natural gas compressed at the surface, injecting it into the wellbore to lift fluid from the reservoir to the surface. That's the common theme between our high-pressure gas lift system, our conventional gas lift, and our plunger lift systems. As you can see on the right, as demonstrated and projected further by Rystad, we think that our forms of lift are growing well north of 10% per year, whereas the legacy forms of lift are growing at roughly half those rates. We completed a very exciting acquisition just in the last six weeks or so, our first acquisition post-IPO. We purchased from Archrock a hundred and fifty-five units that were being utilized for both high-pressure gas lift as well as vapor recovery applications, both two product lines that, again, we are market leaders in. We paid a very attractive price, and we arrived at fair value by really determining what we could build the units for, and these were all pretty much brand-new units built in the last two to three years. What can we build the units for, and what's the current value of the contracts? And there's your purchase price. So in terms of integration, we plugged these systems into our existing fleet operations, hired a total of three people, assumed zero overhead to manage these systems, and novated roughly a dozen contracts from existing customers over to us. We inherited three very key accounts that we had not penetrated to our liking in buying these assets, and importantly, I think solidified our sector leadership in the deployment of high-pressure gas lift systems. We've gotten nothing but positive feedback from our customer base post-acquisition, and Archrock were great to deal with. We consider them really good at what they do. I think they would say the same about us, so this was a real win-win for both them and for us. Okay, so we've been talking about artificial lift. This is the oily side of our product portfolio. I want to spend a minute on vapor recovery. That's the 40% of our business that is in our Natural Gas Technologies business unit. And just as a little bit of a primer, when you produce an oil and gas well to the surface, you have a mixture of oil, gas, water, and other substances that are coming out of the formation. When it flows from 10-15 thousand feet below the surface of the earth at a very high temperature, it gets to atmospheric pressure and ambient temperature. What happens to hydrocarbons when you subject them to that change in an environment is you have a recharacterization of the hydrocarbon. What was a liquid wants to be a gas because of the pressure differential and the temperature change. In the old days, when oil companies used to only want to produce black oil or only want to produce natural gas or methane, they would view these very volatile hydrocarbons as waste products. As a safety measure, or sometimes even just as an efficiency measure, they would send those hydrocarbons to a flare. When you flare those hydrocarbons, you get rid of them as a waste product, but you don't have the ability to monetize those molecules that have BTU content. We, with our customer support, embarked upon a journey to create the world's leading vapor recovery unit, which we've successfully done. We have about a 50% market share in the U.S. today, and we have over 2,500 systems on rent every day to the who's who of the industry. And what makes a vapor recovery unit a no-brainer for an oil company to add to their production infrastructure is the fact that the minute it turns on, it starts generating profit for that oil company. The monthly rental rate can be covered inside of the first month of the sale of the hydrocarbons that come off of the tank battery. So it's been a wonderful success. We're building more every month. This is another organic growth story that we're very proud of. We've attacked roughly 10%-15% of the addressable market. But let me break that down a little bit more because there's actually government statistics to back up our claims here. On the right-hand side, you will see the percentage of tank batteries in each one of the major shale plays that actually have vapor recovery units attached to them to eliminate fugitive methane emissions. And as you can see, in the Permian, over the last seven years, the deployment of vapor recovery systems has roughly doubled. So as a percentage of total, the Permian, on every new tank battery, pretty much, you've seen the vapor recovery system deployed, and it has everything to do with the ability to move that natural gas to market after we capture something that was otherwise vented or flared. We feel like our vertical integration, our customer relationships, and the fact that we've got such a lead in market position in each one of these highly critical production-oriented services, really provides us with a deep competitive moat. We think that the investment thesis that we sold at the IPO is intact. The combination of generating attractive rates of return on existing and future CapEx, as well as the ability to grow in a flat market, we think is a true differentiator for our business model. This page, we're very proud of, and we spend a lot of time with investors educating them on why Flowco, why we stand apart, and why we feel like we should be the first name you think of when you want to think of a resilient, durable OFS story in the North American market. We generate industry-leading returns, while still being able to generate double-digit growth in a flat production environment. With consensus where it is in terms of what production is projected to be in the United States for the next several years, and with our organic growth market share capture story still being prosecuted, we think that Flowco has room to run, and our consensus estimates are obviously there for you to peruse, but we feel really comfortable with where the Street has us this year and next. So we think that this is a true differentiator and are very proud of this stat. With that, I'm 15 seconds over 15 minutes, so I think I've pretty much arrived at the end of prepared remarks, so I'll join you here, if that's okay. Sounds great. Bob, thanks for that overview. So there's a couple questions for you here before we take some questions from the audience. So last year, and again this year, production in the Lower 48 has surprised to the upside, which is frustrating for a services analyst. We hear a lot about drilling and completion efficiencies, and that's probably part of it, but one thing we don't hear about a lot is production enhancement. So are you actually seeing any noticeable change in customer behavior and investing more into production enhancement, utilizing the different types of lifts you provide, like this year, last year, versus maybe, say, five years ago? Yeah. I think what's changed with this market change is, and it makes sense when you think about it just from a human standpoint, whenever a company is growing aggressively, an oil company, right, what are their objectives? They're you know, pushing their service companies to drill faster, frack harder, make do with less, you know, drive efficiencies, and they're focused on the drilling and completion expenditures, right? In times where they're cutting, which is where we are today, they need to make do with what they have and look to their production to sustain their profitability, right? To maintain their production guidance, to actually really pick some low-hanging fruit, candidly, from their portfolio of operations. And that's where we actually shine. In this kind of a market, we have much deeper customer engagement about the right solution in every well, every time, right? So how can we help that customer with the method selection? Those conversations were happening during, you know, periods of more aggressive growth, but not as intimately. And so that's been the real change. Where you see that is really in our share gains, okay? So a customer now is open to a new way of doing something, if you can demonstrate that you can actually provide them an NPV uplift to their production profile with high-pressure gas lift, for instance, as opposed to an ESP. If you can explain to them the economic benefit of a VRU and the fact that they're quite literally burning money by sending something to a flare stack, that's a pretty easy conversation to have in this market. Got it. Speaking of high-pressure gas lift, gas lift systems or HPGL, you mentioned they're displacing ESPs. Are they almost interchangeable? And, like, if a well currently has an ESP today, can they just... "Yeah, I'm gonna take out the ESP"? Or I'm not-- If I'm drilling a new well and I'm producing from it, I was thinking about using an ESP, but I can just use HPGL in place of it and not have to use ESPs at all? So, yes, is the answer. What do you have to have to make the system work? You have to have access to natural gas. You have to have the right kind of initial production rates to make the deployment of the system, from a physics standpoint, actually feasible. And then, yes, you install it, you turn it on, and you let it go. The benefit of the system is, from an operational efficiency standpoint. Our statistics are 99.6% uptime, which means 0.4% of the time we have to change spark plugs and filters on the engine, right? An ESP, in most shale wells, is not the right solution, because an ESP was engineered and built 100 years ago to do a completely different application. Oil companies deployed that technique when oily shales became a thing, because that was the only tool available. An ESP works really well with consistent downhole conditions, a consistent level of fluid, and a very benign operating environment. None of that describes shale production. There's lots of sand, there's slugs of gas that come through intermittently, and there's a decline curve that you just cannot fight. And so when a decline curve kicks in, it makes the pump less effective, and it breaks. So the average uptime on a field that is produced with an ESP is more like 92%. So when you add up that 7% differential between uptime and you do a PV calculation of the production that you are pulling forward because of that better uptime, then we provide a significant value to the customer by switching. Yep. That's how, that's how we actually came to penetrate as much as we did in the market. Now, all that being said, we only think we can displace about half of ESP demand in the United States. Okay. There's an entire other half of the market that has well conditions that are more fit for purpose for ESP production. So we'd like to get all of it, but we don't think we can. What are some of those well conditions? Are they, like, specific basins or...? You could think about consistent production, mature production that's still generating roughly 500 barrels a day. Think water floods, you know, so there's some major water flood activity out in New Mexico and up in the Uinta, up in Utah. It's just... Those are great ESP markets. Offshore, that's an ESP market. But for shale, including some of the international shales, which are now starting to become commercial, I think high-pressure gas lift has a lot to offer. Where are HPGLs in that journey of displacing ESPs, industry-wide? I know, I know you make up a large portion of that market, but you said 50% displacement of ESPs is the addressable market. Yep. Where are we? At the time of the IPO, we actually did some granular work. We were at about 15%. Fifteen, okay. Based on 2023 data, which was the latest available data at the time of our IPO. It's, it's higher than that now. If I had to guess, it's roughly 20%. Okay. But we're continuing to take share, we're continuing to build more systems, and you know, we've got good intel on where the competitive technology is, and they're, you know, kind of treading water. We're gonna actually, we think we're gonna probably come out with some more granular data and update our investor deck in the next couple of quarters. How do you get that remaining 30%? Is it just. Good question. Is it just operators are just so used to using ESPs? There's a lot of that. Their pads are designed for ESP production. Okay. They have a legacy fleet of ESPs that they have made a big investment in. Sometimes it's as simple as, "This is the way I've always done it. I want to continue to do it this way. I'm comfortable with this. And so we push on all those points repeatedly, and we've gone from zero customers to roughly 65 in the last six years. There's more to go. What we've been able to do is, once a customer has tried the technique where it makes sense, they've never gone back. Wow! We've not lost a single customer who says, "I don't really like this. I want to go back to ESP. Great to hear. U.S.-based supply chain, vertically integrated footprint. On the flight, you said you have six manufacturing centers of excellence. Do you manufacture all your lift and VRU products domestically, or are there certain components you import that could be subject to tariffs? Has there been any negative impact from the tariff environment? Great question. The short answer is no. We've actually, you highlighted everything that we emphasize: domestic manufacturing footprint, vertical integration, we make all of our own stuff. But even if you look at our supply chain, it's largely a domestic supply chain. And then, if you look at our suppliers' supply chains, it's largely domestic. So even the knock-on tertiary impacts that could come from tariffs on acquired parts, we've done the work, we don't think it's gonna be material at all. If you look at the competitive artificial lift techniques, largely ESPs, over 75% of all ESPs come from China, and that includes some of the largest, most well-known oil service companies that are buying their products from Chinese suppliers. Now, what are they doing? They're trying to pass tariffs through to customers, number one. But number two, they're aggressively trying to diversify their supply chains away from China, either exclusively or at least partly, so that they can mitigate some of that tariff risk. But it's gonna be a really long road to recreate a domestic supply chain for something that specialized, because it requires foundries, you know, heavy machining, and, you know, I can't tell you the last time we built a foundry in this country. It's been a while. Right. Shifting over to VRUs, it seems like a no-brainer. As you mentioned, I mean, you have fugitive methane that you're flaring, or you could actually earn some cash from it. Yep. What's the conversation like with customers, and is there kind of pushback? Is it just the cost of the VRU system that they're willing- No, it's actually the VRUs historically. By the way, VRU technology is something that everybody in this room has used, right? If you've ever filled up a tank of gas in your car, you've used a VRU. That pump actually is engineered to capture the methane vapor, the volatile vapors that escape when you transfer fluid from tank A to tank B, okay? So it's not a hard technique to do unless you have very volatile conditions, which is what you have on a well pad, okay? You'll have slugs of gas that are produced, they come in, and they settle out aggressively in a tank. And so historically, the VRUs that have been engineered to help manage vapors at a tank battery have not been reliable, okay? So the last 10 years of Flowco's journey has been to invest in technology to improve our uptime from kind of mid-90s, where the industry norm is, to 99% plus, which is where Flowco is. And so that, that demonstrated reliability factor is what we've mostly been selling to customers because, you know, years ago, a customer conversation would be, "I don't want one of these things, they never work," right? Well, now, you know, we've got data to show that they work all the time, and we've got, you know, we've got a P&L to show them that what they capture is actually extremely volatile. A lot of times, too, when we get questions from investors, not necessarily from customers, but, you know, that, "Isn't this tied to natural gas prices, and aren't you concerned about sustained low natural gas prices causing headwinds for the demand curve on VRU?" and the answer is no, because when you're capturing natural gas vapors, you're not just capturing methane molecules, you're capturing the natural gas liquids that are embedded within the hydrocarbon itself, so high BTU gas. So we've done the analysis, in a typical Permian pad, what is a $2.50 Henry Hub molecule that you're capturing is actually more like $10 because of the BTU uplift you get from the sale of the NGLs, the butanes, the propanes, and the pentanes. Interesting. It's a very economic add-on to a production infrastructure spend. Got it. I just have one more question for you, but we do have maybe, yeah, time for one or two questions from the audience, so we'll get the mic on. My last question is just on M&A. You recently acquired 155 HPGL and VRU systems from Archrock. But how many total systems do you now have of HPGL and VRU, and are you done with M&A for the near term, or are you looking to continue to expand? We don't disclose how many specific individual pieces of unit that we have, but we have over forty-five hundred total rental systems between high-pressure gas lift, vapor recovery, and conventional gas lift. Okay. Definitely not done with M&A. We have, I think, a structure, a culture, and a very clearly defined M&A strategy. Very clearly, we want to be able to credibly approach a customer and say: We want to be your chosen partner in all phases of production, and so we've got gaps in our product portfolio that we'd like to fill in. We've got other things on the natural gas side that I think can make some sense that are in adjacent sectors. Great. Just on the methane recovery business, you know, as the pipelines come along in the Permian and de-bottleneck to get the gas out of there, is that considered a direct competitor to you, and how do you compete with that, or? No, the methane vapors that we capture are at the well pad, okay? So as more well pads get constructed, there's more addressable market for us to actually go deploy our solution. As gas moves down the value chain, it's got to go through gas processing, which is another place where you do need vapor recovery, and then it has to go through various compressor stations, which also struggle with fugitive methane emissions. So actually, in our last couple of quarterly calls, we've highlighted midstream as not necessarily a headwind for us, but more likely a tailwind because we think there's more market that we can get by selling VRUs into that midstream buildout because there are multiple points along that system where methane vapors can escape. Would it be the same VRU system that you could just apply to midstream? It is. A smaller unit, typically, because the volumes are less, and I think midstream players would view this as infrastructure spend versus a rental item. So I think you could see us sell multiple systems to midstream players, but you're talking hundreds of systems here because these are obviously large, very large companies with huge networks. So the opportunity is big, but it would be on the sale, not the rent. Got it. Any final questions? All right, we'll leave it there. Joe Bob, thanks for the time today. You bet. Thanks for having me. Appreciate it.