WaterBridge: Oil and Water - [Business Breakdowns, EP.228]

Today, we're breaking down the recent IPO, WaterBridge. I was joined by James Davolos from Horizon Kinetics, and this one was a long time in the making. As you'll hear in the episode, Horizon Kinetics has a long history with these unique, capital-light, high-cash-flow-potential businesses, most notoriously with TPL, Texas Pacific Land Trust.

I had been pursuing Horizon Kinetics as a guest, but it wasn't until a friendly listener, Chris Polk, made the connection that this all came to life. So we start the episode with a bit about Horizon Kinetics' history with these very unique businesses that are off the radar for many, with TPL, LandBridge, and now WaterBridge.

Then we get into the weeds and nuances of what this business actually does, why this disposal water and the service they're providing are so incredibly important, particularly with U.S. shale, and where they are in the Permian Basin. This is an interesting one from all different angles, and it's a timely one, which is always special.

All right, James, I am excited to have you here. It's a timely Business Breakdowns. We're here to talk about WaterBridge. I think we're going to get into a bit about LandBridge as well, the overall space, and what these businesses represent in the market. Maybe you could just start us off with a simple introduction—how you would describe WaterBridge, and maybe even LandBridge, to a broader audience to get them familiar with what's going on at these businesses.

Sure. First, I want to say thanks for having me. I've been a big fan of the podcast and everything at Colossus for a long time now.

1. WaterBridge Handles Produced Water

I think let's start with WaterBridge. WaterBridge came public yesterday, and WaterBridge is the leading water infrastructure company in Texas. Unlike traditional water infrastructure, which you might be familiar with—utilities that generally treat, dispose of, and move water around in residential and commercial systems for consumption—this is actually a waste byproduct that's part of the oil and gas extraction industry.

I think a lot of the listeners will be surprised to learn that in the Delaware Basin, which is the largest and fastest-growing part of U.S. oil production, about 4 barrels of this water are produced for every barrel of oil and gas. It's a lot, suffice it to say.

LandBridge is already public. It came public a little over a year ago, and the way I think about it is that they are the land company with basically triple-net leases that facilitate the activities of WaterBridge and other infrastructure companies operating in that Texas ecosystem. While the core business is driven by water, there are definitely some next-generation things in power generation, transmission, maybe data centers, et cetera.

It's a very helpful overview, and these are unique businesses. I would almost say they're a class of business—not quite an asset class, but a class of business. I know Horizon Kinetics has a history in this space. Can you talk a little bit about the history that would result in these coming onto your radar and a little bit about that background?

2. Horizon Kinetics Finds Land

Absolutely. I can't take any credit for it because you're going back to 1995, when the firm was founded, and I was 11 or 12 years old.

But Murray Stahl, our chairman, came across this funky liquidating land trust in Texas that was listed on the NYSE called Texas Pacific Land Trust. The original thesis was very simple. We actually have a research report that he issued publicly back then, and it was essentially this: The company was created through the bankruptcy of the Texas and Pacific Railway in the late 1880s.

The idea was to connect Texas to Southern California. People who remember the history of that era, and the robber barons, railroads, and leverage, are pretty familiar with the fact that it didn't end well. They got land grants for every mile of railroad that was built in the state of Texas.

It was impossible to sell off a couple million acres, certainly in 1888, probably no less so today. So they listed it on the NYSE, and it was a liquidating trust. Basically, they would take their proceeds—much of it was from grazing land, and later some small oil and gas royalties—and then buy back stock or pay dividends.

But if you bought back stock at a lower value, you were effectively buying back acreage at a lower implied price. So if you're buying back stock at an implied price of $10 an acre, and acres on the fair market were $100, it was the most accretive compounding machine you've ever seen.

That was the thesis. Obviously, things have changed dramatically with fracking, the development of water, and the development of the Permian Basin. But our history with that company, which is now a corporation, and Murray being on the board of directors, was one of the earlier windows we had into this large, nascent water infrastructure industry within the larger U.S. energy complex.

Yeah, it's a fascinating background—the railroad story and them getting those grants. It's something that came up on our Union Pacific Railroad episode, where their assets were eventually sold to Anadarko for $4 billion 25 years ago. So it's interesting to see how these assets and grants have preserved some interesting value over the years.

How would you define this group, or this concept of investing, if you could, in a snapshot? How do you frame it or approach it in just general terms?

You can look at the broader energy industry, and most people in energy look at 3 different business models, with nuance to each.

You've got your companies that are primarily E&P, or exploration and production. They drill, and they make their money basically drilling for hydrocarbons. Then some of those companies can be integrated, where they're fully upstream, which is drilling.

The second set is midstream, which would be transporting those hydrocarbons. The third would be downstream, which would be your refining and then your retail petroleum station.

Those are the 3 traditional verticals. You can add a slight adjacency via oilfield services—the companies like Schlumberger and Halliburton, maybe some of the offshore companies that do services that are ancillary but part of oilfield energy extraction.

Those businesses tend to be very capital-intensive and very cyclical. Some of them have more stable cash flows, but generally they're all somewhat cyclical relative to the volume and the pricing of oil and gas markets.

We prefer to look at companies that have lower capital intensity and less cyclicality. Now, you can't remove all of that, but our protracted history of investing in Texas Pacific and then other companies within the ecosystem led us to the conclusion that land—and land in Texas—has really 2 different types. There's surface acreage, and then there's the mineral estate. In some cases, they are one and the same.

But land is the preeminent asset because it's essentially a pure-margin business that's perpetual, with optionality. Within land, there are minerals or royalties. There's a variety of royalty companies that are public now, but if you were to think about Chevron, Exxon, and Conoco, they're spending hundreds of millions, if not billions, developing their U.S. energy position.

The royalty holder is literally earning a percentage of the oil and gas that they produce, off the top. So you participate in no OPEX and no CapEx. In Texas parlance, they call this “mailbox money,” because if you're so lucky as to have a ranch and Conoco's operating that lease, you just go out to your mailbox and pick up your check every month. It's a pretty good gig if you can get it.

Beyond royalties, within the surface acreage world, your surface acreage can be monetized in any number of ways, primarily through easements: easements for pipelines, easements for power, easements for access roads, power lines, et cetera.

But we've also honed in on the infrastructure side of it with water. Up until very recently, there was really only 1 pure-play water infrastructure company, which was Aris, and it was sold to Western Midstream.

Coincidentally, going back to your comments about Union Pacific and Anadarko, Western was the midstream assets of Occidental, which acquired Anadarko. That was very contentious but supported by Berkshire Hathaway. A big part of the assets that were bought by Anadarko is actually something we might talk about later in the sour gas window as you get to the eastern edge of the Delaware Basin.

Anyway, going back on topic, we look at it as surface acreage, and then, within that surface acreage, royalties, where we're very active in a variety of companies. Now, we also look at companies that can be very dynamic in monetizing that surface acreage, like LandBridge, whether through water or other types of easements, and then the water infrastructure that's operated, which is the WaterBridge business model.

Yeah. And maybe we can get into a bit of what's happening with the production of those 4 barrels of water for every 1 barrel of oil in this region.

Can you talk about what that looks like in practice and what WaterBridge is actually doing as a service with that water?

3. The Produced Water Problem

Maybe a little history, just to bring people up to speed on exactly how this works. The Permian Basin is the largest oil and gas-producing region in the US, at around 11 to 12 million barrels of oil equivalent, which includes natural gas and natural gas liquids. Relative to a little over 100 million barrels a day of global production, 10% of global volume is enormous. It’s even higher when you look at just oil.

These are the oily wells in the US, and the broader US production is influenced by gas and these natural gas liquids. The reason the Permian Basin in West Texas has hydrocarbons is that it’s an ancient seabed. Decomposing carbon is where you have hydrocarbons over hundreds of millions of years.

It shouldn’t be surprising that when you break up this shale rock, where there are oil and gas molecules trapped in it, there is water. What should also not be surprising, given that it’s an ancient seabed of decomposing carbon, is that it’s very high in salinity, or salt content, just like the ocean.

Now that we’ve established that, you’re going down, in some cases, 3,000 to 5,000 feet deep, and in other cases, 10,000 to 12,000 feet deep. You’re breaking up 1-, 2-, and 3-mile sections of rock, so now you’re getting beyond 3-mile fracks. You have all of this water going into the wellbore and coming out with the oil and gas.

The first thing you need to do is separate your oil and gas from this water. As I mentioned earlier, in the Delaware Basin, you’re getting about 4 barrels today—about 3.7, to be exact, based on the latest data—of what’s called produced water with your oil and gas.

This water is not like seawater. It’s actually many magnitudes more saline than seawater. It also has a variety of corrosive compounds and very high total dissolved solids content. In every sense of the word, it’s a waste product, and it needs to be remediated.

In the days of vertical wells, where you just drilled down vertically and it was a pressure system, there was nowhere near as much water because you weren’t breaking up rock. You could also take this produced water and reinject it into the well to increase pressure, which is called enhanced oil recovery.

This industry was completely nonexistent before the shale boom, call it 2014. To be generous, it’s about a decade old. But as the water increases, you need to dispose of it. In the early days, if you were a large E&P, maybe you called up a rancher next door who had some scrubland and said, “Hey, can I inject this water? I just have to get rid of it?” Generally, it was found money to the rancher. They didn’t care.

As you started getting more and more volume, they were going deeper, and it made sense to go deep below the shale. Yes, it’s more expensive to go deeper, but you don’t have to worry about interfering with the oil and gas formation. If you think about the shale like a layer cake, you inject it above that layer cake, and somebody has to drill through it to get to their oil and gas. So that presents issues in and of itself.

The problem with going below the oil and gas is that down there is where there are natural fault lines, and it’s more susceptible. It’s higher pressure. So bookmark this concept of pressure, pore space, and porosity.

These deep injections started creating seismic events, or earthquakes. That caught the attention of authorities. In Texas, it’s the Railroad Commission.

More recently, about 75% of these disposal wells have been shallow. Shallow also has issues. First, you do not want to interfere with your oil and gas formation. If you interfere with somebody’s ability to extract their minerals, you can be held liable, which is a huge liability relative to what you might be getting—10 or 12 cents a barrel for water disposal.

More recently, as you’ve had this pressure increasing, you’ve had sinkholes and interference with these old legacy wells. Remember those vertical wells I talked about? Vertical production peaked in the ’70s, and some of these wells have been capped for decades.

Now you’re injecting all of this water into these shallow formations, and if you’re not responsible with your pressure, it invades these wellbores. In some cases, you can have a blowout of this brackish brine water with all of the nasty associated chemicals, solids, and compounds.

As you sit today, we are running out of, quote, “pore space.” Operators need to be very thoughtful about how to transport and remediate that water because it’s no longer as simple as calling up your neighbor and saying, “Hey, what is it going to cost for me to dispose of this water?”

You need somebody who can guarantee that you are not going to be shut in on your well because you can’t get rid of your water. So a company like WaterBridge is a third-party operator, versus something that used to be handled internally by maybe the midstream and marketing team. They can say, “Look, I can guarantee your billion-dollar pad-drilling plan. If you’re going to need 50,000, 100,000, or even a couple hundred thousand barrels of disposal, here are my injection wells. Here are my pipelines.”

Then, if this gets filled up, they have these long-haul pipelines to even take it out of the basin. Now you don’t have to worry about something that, first, could completely curtail your ability to produce, and second, is getting increasingly expensive and prohibitive.

If you’re paying $1 a barrel to get rid of water and you have 4-to-1 water cuts, that’s $4 of your LOE, and you’re lucky if you’re netting $40 in the Permian when you take into account the NGL and gas mix of that barrel. So it’s a big deal.

The point is that third-party companies that specialize in doing this can guarantee that disposal and that flow. They can do it in a way where you’re not jeopardizing environmental or regulatory issues. They are now absolutely critical infrastructure points for the entire US energy ecosystem.

Yeah, it feels like they’re solving a pain point and removing one of the logistical things that a producer would need to worry about. I would imagine WaterBridge owns the infrastructure, like you mentioned—pipelines, and possibly wellbores. Talk about that: what infrastructure do they have to own to facilitate this service, and how are they finding ways to dispose of this? Is it just a network of wellbores from other producers? What goes into the mechanics of having the capacity to dispose of this?

4. Building The Disposal Network

If you start at the life cycle, they need an ability to take control of that water at the wellhead, which is operated by the E&P company. They separate the skim oil. A very small part of WaterBridge’s business involves separating the residual oil in that stream.

The 2 critical parts of the infrastructure are pipe and land. Anywhere from 16- to 24-inch-diameter pipe, just like an oil and gas pipeline, needs to transport it. In some cases, you’re talking a matter of yards. In other cases, you’re talking hundreds of miles if you need to get it out of the basin.

The next part is land. In some cases, you’re just getting easements from third parties, where you’re paying an easement to cross their land. In other cases, with LandBridge, you own the land, and LandBridge obviously has a symbiotic relationship where they lease it to WaterBridge.

After that easement, you then need the saltwater disposal well. A saltwater disposal well is owned and operated by the company. As you can imagine from my explanation, these are pretty complex. You’re drilling fairly deep. Even going into the shallower formation of the Delaware Mountain Group, you’re still going thousands of feet deep.

This is a pretty nasty waste product, so it needs to be encased in steel and concrete. The WaterBridges of the world have a lot of technology to monitor downhole pressure, make sure you don’t have leaks, and monitor flow rates.

To answer your question in a PP&E sense, your PP&E is the land, the pipe, and the actual disposal wells themselves. But the limiting factor today, which is making it harder and harder, is the land—the pore space and then the easements. There are any number of places where you can drill these saltwater disposal wells.

For people familiar with Texas, if you’re way out in the middle of Culberson County or you’re up in the Panhandle, in Crane County, sure, there’s plenty of pore space. But it’s the ability to take a pipe and get it there. The areas around the state line, where New Mexico and Texas meet, are very scarce.

Having incremental disposal capacity there is incredibly valuable, as is the ability to have offtake, which is going to get it out of the basin.

Yeah, I certainly get the offtake. I can understand the land side as well. To go back to what you were mentioning earlier, in this case, WaterBridge is getting easements from LandBridge if they’re moving over that land. Are they also leasing the land or using LandBridge’s land in the case of the wells themselves?

It tends to be an all-in contract. Let’s say I’m using a couple dozen of your acres, and then I have a couple of SWDs on your acreage. It tends to be priced on a per-barrel basis, which is better than an easement because term easements tend not to be as lucrative. But we can get into the contract structures later.

You want to have that optionality around volume and pricing. In this sense, the landowners that are astute retain that.

Got it. I think you’ve given a pretty good rundown of the Permian, its importance to the overall industry, how it captures this idea of fracking in the US, and how that unlocked so much resource that had previously been left behind before we really dialed in on the technology.

Regarding that basin and its future dynamics, I'll lead off with a simple question. It's very unique when it relates to shale oil, where you have very rapid decline curves. There's an incredible amount of oil produced from these wells, and a lot of that is seen up front. From a time value of money standpoint, that could be a good thing, but it means you need to drill more to maintain that production. Do any of these things, as they relate to shale and the unique dynamics of shale oil, have an impact on WaterBridge when you think about the opportunity, both medium term and then, obviously, longer term as well?

5. Water Volumes Outlast Oil Declines

Absolutely. I think this is one of the biggest misperceptions around the business today: the dynamic you mentioned. Decline rates on a traditional shale well might be 30% or more in your first couple of years, and then pretty high thereafter, before you flatline into a much slower, more traditional decline rate. But that dynamic people have cited as the treadmill—where you have to keep drilling at an ever-higher rate just to maintain production, let alone grow—is different with water. Maybe we'll introduce this concept of water cuts: a water cut is how much water comes out with the oil and gas.

When you first start producing a well, the water cut is actually at its lowest because you have a lot of that oil and gas going into the wellbore. But then, after those really steep declines, your water cut gets higher and higher and higher as that well ages. Despite the overall decline in the volume of oil and gas from that well, what's actually coming out of the ground is a very similar volume; it's just more and more water. There's almost a very stable rate of water over the decades that that well produces. As the well ages, the water cut goes up, so you don't have to have this treadmill just to maintain production. It's a much longer, more stable, contracted stream of water, and that's why it's such a big deal. You drill one of these big wells, you're going to have a couple-million-dollar estimated ultimate recovery, or EUR. You've got decades, maybe 30 years, of water liabilities that you need to figure out.

The other concept that's really important is that people have been hypothesizing the end of the Permian based on this concept of high-grading Tier 1 locations. Nobody's really defined Tier 1 other than as the lowest-cost locations to drill. Once you go into Tier 2, it tends to be these deeper formations in the Wolfcamp. Why is it Tier 2? Maybe there's a little less oil in place, but it's also more expensive to extract. It's not more expensive because you're going deeper, per se; it's generally more expensive because there's more water.

As you see operators drilling into lower-tier or lower-quality areas, you're going to start seeing that 4:1 ratio inch up to 5:1 or 6:1. There are even areas where, if you believe, as we do, that the Permian is going to be producing for decades, you could be in scenarios where some of these wells are over 10:1. Those are the 2 really important dynamics: A, the water cut increasing as the well ages, and B, the water cut increasing as you go into lower tiers. This basically creates a much more stable, even organic growth rate for water. If the Permian produces flat oil for the next 20 years, water volumes will grow almost certainly in the mid- to high-single digits, if not higher. I don't think very many people appreciate that.

I can tell you I definitely did not appreciate that, and it's a very important detail. Perhaps I buried the lede with that question, waiting to get there. That's an incredibly interesting dynamic, both in the difference in decline curves for water versus oil from a traditional well, and in what it means when you're theoretically moving down in quality. I guess when you think about the Permian, obviously, I think that is the basin within the U.S. Would this theoretically translate into other basins, like the Eagle Ford, the Williston, or the Bakken? I don't stay too close to basin production anymore, but I'd be curious to know.

The short answer is no. They don't have nearly as high water cuts, but they also don't have nearly the amount of oil and gas produced. Maybe many decades out, if we really need to exploit different reservoirs, but for the time being, the opportunity is very acute and the largest in the Permian, specifically the Delaware.

I have to bring up Five Point Energy because you can't read about WaterBridge or LandBridge without reading about Five Point Energy. They seem to be the sponsors behind these companies, but I think you have a much better appreciation for who they are and what they've done. Can you give us a snapshot of Five Point Energy?

6. Five Point Builds The Platform

Absolutely. One of the things I've loved about guests on your podcast is how much they stress the importance of people. In this case, the people really start with David Capobianco. David's history is really interesting. He was your traditional banker with midstream experience. He went to work for Vulcan, which was Paul Allen of Microsoft, Bain & Fortune's family office. He took Plains All American, which is one of the larger oil and gas pipeline systems in the U.S., private.

Based on the filings and legal analysis done by my trusty AI assistants, David was terminated and then replaced by his team in an effort by Vulcan not to pay him what was ultimately disclosed as a $20 million settlement. David and his partner won when they litigated that in court, but the genesis of his dismissal at Vulcan and his familiarity with midstream was ultimately what started WaterBridge.

That gave him the opportunity to go out and create Five Point Energy in 2012. He did that based on what he had learned from being in the midstream space: “I want to be in water because this is only going to get bigger and bigger, and eventually you're going to need third parties to be involved there.” One of his initial transactions was acquiring a water company run by Jason Long, who's now the CEO of WaterBridge and LandBridge, and he basically built WaterBridge from the ground up as the premier water-disposal infrastructure company. It's a really fragmented industry. They did a lot of organic things, but they also did a lot of bolt-ons.

Eventually, they came to the realization that it was going to be really difficult to scale this to the aspirations they had if they were constantly having to call up these ranchers and get access to their land. One of the really unique deals they were able to structure—and I don't think many people could have pulled this off other than David and Jason—was an area of mutual interest, essentially a joint venture with Texas Pacific Land Corporation, to really exploit that state-line area in northern Loving County. It's a really symbiotic relationship. TPL doesn't operate water systems. They're more of a royalty taker on the saltwater-disposal wells.

But then, also in the wake of COVID, they were able to buy the Hanging H Ranch. When I say they, I mean Five Point. Five Point had some really interesting midstream assets, including San Mateo. They had an acid-gas injection company called Northwind, which we should talk about later. They raised the capital to go out and say, “Look, we really want to get some surface acreage to facilitate the growth of WaterBridge.”

The Hanging H Ranch was actually under contract by a private-equity-backed sponsor, and they were unable to close during COVID. David and Five Point fortunately stayed in the vicinity of the deal and were able to close on it in 2021. It was about 70,000 acres, really in the core of the core of the Permian Basin.

So now you've got Five Point as your sponsor company, WaterBridge, and then you've got the land company, LandBridge, with that first toehold of around 70,000 acres from the Hanging H Ranch. A lot has gone on since then, but I should also mention—and I definitely want to stay on Five Point—that when you look at the development of the basin, first, they've been very forward-thinking with sour gas and Northwind, which they just sold to MPLX.

They also launched a new company called PowerBridge. If you're of the belief, as we are inclined to be, that you're going to see large-scale data centers and infrastructure coming to Texas, PowerBridge is now another portfolio company of Five Point, run by the former Talen CEO, to really facilitate that development. The commonality here is very forward-thinking, very aggressive, but thoughtful deal-making. It really speaks volumes to what they've been able to achieve and to our willingness to partner with them.

Yeah. It's very interesting to hear. I think so many people tried to be opportunistic, particularly after the fallout from the shale boom, and that took many different routes, but I don't think you saw too many successes. This one is quite interesting from an infrastructure perspective. I'm curious, from your standpoint, when you think about the different vehicles, I guess the simple answer is you'd rather invest in a pure play than have these pieced together. But do you think there's anything else beyond that separating LandBridge and WaterBridge? I understand they're 2 different businesses, but from a scale standpoint, sometimes it helps to bunch things together. Any thoughts on their approach to doing that?

Yeah. I think you would never get the appropriate multiple of land within a broader portfolio. We've seen this with gold royalties. Newmont Mining bought Franco-Nevada and then spun it back out at the end of 2007 because it got frustrated that the market would never give it credit for its royalties.

You also see oil and gas companies that don’t get credit for their surface acreage and their royalties. And so I think what Five Point recognized is that land is a really unique asset with very high optionality, and we need to keep that separate because it really should be capitalized at a different rate than an operated midstream asset. I think it’s also important to keep water as a pure play.

There are a variety of companies out there that have water within a broader midstream business. NGL has a water business. Western Midstream has a business that is now larger after acquiring Aris, and Aris probably never got the multiple that it deserved. But I think it was really important that, if you want the market to appreciate and capitalize this business appropriately, you need to allow investors to isolate the water business for what it is.

Does Kinder Morgan still have a water business?

I believe they do, but I don’t know how big of a market share. They don’t really come across as having a big market share in the Permian, at least.

Yeah, okay, that makes sense. I guess it is helpful to touch on LandBridge just because you do have these 2 vehicles. LandBridge had this previous IPO process a year ahead of where WaterBridge is today. Can you talk through a little bit more of a snapshot of whether they’re doing anything beyond what you’ve referenced about what they do with WaterBridge? And then what has been the public market perception of LandBridge since that IPO?

Yeah. It was actually not the greatest IPO. Even though the stock has done really well, I think it was originally slated to price in the $19–$22 range, which was around 15 times trailing or forward EBITDA. It ultimately broke price and traded at $17, and people can pull up a chart. It traded at $80 by year-end. It’s in the mid-$50s today.

There are a lot of different things going on there, and I think that creates the confusion. But if you just underwrite the core business, which is assembling ranches that are very complementary in Texas and New Mexico, which can facilitate water infrastructure development, it’s a very compelling investment case.

Five Point has been really forward-thinking and also developing these next-generation opportunities. They’ve identified 6 or 8 facilities where they think it’s essentially plug-and-play for multigigawatt data centers in West Texas. You’ve got your fiber to plug in your fiber optic. In some cases, you can get some grid power, but I think a lot of this is going to be direct generation. You’ve got the ERCOT grid, you’ve got the substations, and, critically, you’ve got the water.

You’ve also got the gas, which is really cheap for direct generation. And so they basically have it ready to go. I think that once the hyperscalers and the other people involved here realize you can’t co-locate a 3-gigawatt facility, let alone 500 megawatts, anymore, all those things have been gobbled up. I think you’re going to start seeing a lot more traction there.

With LandBridge, a lot of the narrative has gotten taken over by these next-generation opportunities. As great as they are and as much as we believe in them, people ignored how great the water opportunity is today. And I think one other thing that LandBridge has talked up is the beneficial reuse of this water.

To the extent that some of it is being, quote, “recycled” today, which is just being cleaned up enough to be used in refracs—a fairly low bar—the next iteration of beneficial reuse would be to desalinate it. Then, can you use it to replenish the Pecos River watershed? Can you use it for crops? Can you use it for animals? And ultimately, could it be used for industrial uses, whether it’s power plants or cooling, things like that?

All these things are incredibly exciting; they’re call options. But I think the market maybe got a little too excited about them happening now versus T+1, T+2, or T+3. Anything interesting going on in West Texas—land and infrastructure—rest assured that they’re involved, or at least looking into it.

Yeah, certainly, it seems like it from all angles. I guess someday they can take the name Liquid Death, but if there’s some questionable name on the water that I’m drinking, I’ll make sure to know whether it’s coming out of this space. That’s a long way out—T+25, I suppose.

Moving to the WaterBridge IPO, I think you captured the opportunity and the trajectory of growth. Can you talk a bit about the contracts themselves? You mentioned some references to a cut of per barrel of oil, but how does it work with the E&P when they’re contracting with them? When does it happen? Is it a flat rate per barrel? Anything you can get into around those contracts?

7. Contracts Lock In Water Demand

Generally, as an E&P, you’re not going to even start thinking about drilling a large development right now unless you know for a fact that your water is taken care of. In this case, the contracts tend to be very long-term, so I believe WaterBridge’s weighted-average contract is around 11 years.

The 2 main types of these long-term, fixed-fee contracts are what’s called an acreage dedication, which is really the preferable term. You have 30,000 acres where you control the drill bit. Give me an acreage dedication on that, and basically I will guarantee your flow at X per barrel. They tend to have CPI-linked escalators, so in the higher nominal-growth world, you have that growth working in your favor.

In our view, as this becomes more and more scarce, there’s going to be pricing power as these contracts reset, although that’s a decade out. There are also minimum volume commitments. A minimum volume commitment would say, “Look, I’m going to guarantee you X amount of volume.”

These aren’t as great because you really want to know you can capture all of their water, but they can be used to say, “Look, I can de-risk a large project. Let me get it started with a minimum volume commitment,” which, again, tends to be a long-term, fixed-fee contract with CPI escalators. It’s just that there’s only a minimum guarantee. But if that can de-risk my project and then I can bring on new customers and quintuple the size of the de-risked project, it’s a home run.

The smallest part is spot, and you always want to leave a little bit of room for spot, which is basically when somebody’s in a jam. They need 20,000 barrels a day handled for a month. You can extract a lot of economics on those contracts, but again, they’ll probably try to figure out a way to mitigate that on their own, so it’s not recurring or nearly as stable as the other types of contracts.

We think that, as the market is reckoning with the fact that we’re running out of easy pore space—and nobody’s denying it anymore—some people are downplaying how big of a deal it is. Other people are downplaying whether it’s an issue today versus 2027 or 2028. But everybody acknowledges there is not enough disposal capacity, either from a transportation or a disposal-well standpoint.

As a testament to this, Devon Energy, in a first-of-its-kind transaction, has paid WaterBridge for the right to use pore space in the future. That’s them saying, “We might not get to this well pad for 3 or 4 years, but we’re worried you’re going to fill up your capacity around it between now and then. So we’re going to pay you to reserve that pore space for us if and when it comes around.”

If that’s any indication, we think there’s going to be some pricing power as they add capacity and as these contracts renew. But even at the current state, they’re long-term, fixed-fee, CPI-escalator, almost utility-like contract streams.

Yeah, that’s a pretty remarkable deal for Devon. Reserving that space and thinking that far in advance contradicts a lot of what the producers do in the oil world. On the point about the minimum guarantees, should I just think about that as anything that is produced on that acreage is ultimately going to go to WaterBridge from a water standpoint?

It’s just a matter of you might only be at the minimum levels for a period of time if the producer doesn’t choose to produce more. It’s mostly about the timeline. It’s not about somebody else coming in and doing some of that disposal.

A minimum volume commitment is just what it sounds like. They might guarantee you 20,000 barrels a day. But to the extent that they could find a way to do it internally or more cheaply, or go around you, it doesn’t guarantee you all that flow.

And so that’s why the acreage dedication, where there are actually penalties for not using them for some of your disposal on that acreage dedication, is much more powerful. Again, it does make sense to do minimum volume commitments, but an acreage dedication is much more attractive long term.

Yeah, the MVCs saved some of the midstream companies, at least for periods of time. But that’s an interesting dynamic. I was thinking that all of those were associated with acreage commitments. How easy is switching in this case?

If you were using an alternative provider, is there low friction associated with substituting someone in, whether that would be in that example or at the end of 10 years?

It’s getting really, really hard to switch because, again, of this concept of porosity. A lot of these saltwater disposal wells, let’s say in West Texas, are on acreage that tends to be in these 640-acre, or square-mile, sections.

So even if you’re being responsible with how you’re injecting on your section, you have no ability to control what your neighbor’s doing, which in some cases could be just a couple hundred meters away, and you’re seeing this high and increasing pressurization. And so now that you’re seeing more discretion around permits for the wells and issues with porosity, it’s getting harder and harder to change vendors.

Once you add in these longer-haul pipelines that are going to be required, then it’s going to be incredibly difficult because there are only a few companies that are even in the business of doing longer-haul pipes today, with WaterBridge being the most well-known and highest regarded.

But I really think it’s going to end up being an oligopolistic industry, where today a lot of it is controlled by the E&P. Internally, ConocoPhillips deals with its own water, but it really isn’t in the business of dealing with 80 miles of easements, drilling disposal wells, and maybe commingling some third-party volumes. I’d say the answer is that it used to be very easy; now it is difficult, and I think in the future it’s getting closer to infeasible than just difficult.

And in those cases, if you have a transition toward outsourcing, does that come with potential for M&A? Do a lot of these producers that are handling it on their own have infrastructure inside their businesses at this point that would be valuable to acquire? Or is this more likely to come in the case of WaterBridge organically building out the infrastructure necessary to work with them?

Probably the former. One of the biggest holders of WaterBridge equity is going to be Devon, because Devon said, “Look, I’m better off contributing this asset to you, letting you run it, and then letting you handle my growth.” In that case, they just contributed that. Aris Water Solutions, which has recently been sold to Western Midstream, though this hasn’t closed yet, had ConocoPhillips as one of its biggest holders because a legacy Concho system was contributed.

So I think you’re going to see more and more operators say, “Okay, it makes more sense. Let me just contribute my system, let you operate it. Just guarantee me I’m going to get what I need through partnering with you.” It’s interesting you mention that, because it wasn’t that long ago that conversations were like, “Hey, the big, big, big integrated players”—so mostly Chevron, Exxon, and ConocoPhillips—“they’re going to handle it themselves.” And now it’s actually, well, when we did deals with them, it was some junior person in the marketing team who dealt with their gathering systems and their pricing. Now it’s up in the CFO’s office, because if you’re talking $4, $5, $6 with your LOE, this goes directly into every decision at this company.

So not only has it been escalated in terms of priority for these companies, but now they’re saying, “Look, we’re pretty good at handling things when we can do it on our acreage, in our footprint,” but once you start adding complexity with geology, easements, and multiple landowners, it increasingly makes sense to utilize third parties. So, just to close this circle here, I think there’s going to be very large market-share growth for third parties, some of which is going to be organic, and then some of which is going to be consolidating systems. Some are E&P-owned, and a few out there are still independent.

Just a very interesting theme that you mentioned. Anytime you see a decision that moves from inside the operational office up to the CFO office, it’s a real thing and it has a real impact. You just have to figure out what type of impact it’s going to have in the industry. So, interesting to hear, and it makes a lot of sense.

I guess when you think about the pricing, I have a few different frameworks in my head just in terms of value capture relative to the E&P. You can only get a certain portion of whatever the oil is selling at, or whatever they’re profiting from, but you also have to earn a return in terms of whatever your costs are. So, if we’re going to use the hypothetical $1 per barrel of water, $4 per barrel of oil, how does that equate back to their own cost line, their own margin profile? Can you just generalize what that means for them and how much fluctuation there is in terms of that pricing?

Yep. For produced water, which is really that basic business of taking the water from the wellbore, transporting it, and disposing of it, they’re getting about $0.78 a barrel right now on a run-rate, pro forma basis for handling that water, and that includes a little bit of skim oil. But about 85% of their pro forma revenue is just handling the water. 8% is skim. The remainder is mostly this water-solutions business, which is cleaning it up for refracs.

Again, $0.78 with an adjusted operating margin per barrel of about $0.44. So call it about a 56% operating margin on a per-barrel basis. The consolidated EBITDA margin of the business, on a run-rate basis, where they’re just shy of a $400 million run rate of EBITDA, is running around 51%. So, fairly high-margin business.

But to your point, I was referencing dollar rates. One of their newer projects is getting water from New Mexico east over the state line on a new pipeline called Speedway into Texas. And this is important because New Mexico is far more stringent in its permitting. In some cases, notwithstanding the newer crackdown on permits, you could get a Texas well permitted in weeks, if not a month or two. The average permitting time in New Mexico was over 2 years.

Wow.

And a lot of people don’t realize that a huge part of the Permian Basin is in New Mexico. Lea and Eddy counties are juggernauts of U.S. energy growth. So it’s easier to build a long-haul pipeline to get that out of New Mexico into Texas. The big gold mine has been that lower state line, so the southern border of New Mexico. Speedway is going to take water east over the eastern border into the Texas Panhandle. So, yes, there is a higher incremental capital investment, because you’re building a long-haul pipeline to get it over that border.

But one of the interesting things when talking to them is they’ve identified about $3.5 billion of CapEx, which should contribute about $1 billion of EBITDA on a fully utilized basis. So call it around a 30% unlevered return on incremental invested capital, and as you start having higher pricing power and you start having higher utilization, I would expect these numbers to drift higher. And so the reason that you can have such extraordinary returns on incremental invested capital is the ability to control the land and then scale the business. And so it’s not the same as how difficult it’s going to be to capture if you’re going to try to expand oil and gas pipelines.

Yeah.

And I think that’s another nuance: the returns here, and then the ability to get these systems online and capture market share, is just a completely different universe. I’d say it’s superior to midstream.

Yeah, I mean, midstream, especially once we’re talking about some of the state lines that they try to cross, is a totally different ballgame. The $3.5 billion of CapEx, is that spread out over a long time period, or is that all going to come quickly?

So that’s just what they’ve identified from a theoretical standpoint. I don’t want to represent that as being guidance, but as an indicative case study of what hypothetically could happen if this really comes to fruition. But to the extent that that does come, I’d say it would probably be spread out over 5 to 10 years, depending on how quickly some of these developments come to bear.

Something else just popped into my head that I feel like we should touch on, which I forgot. Going back to my comments earlier, in Texas you have the surface estate, which is the surface, just like your fee-simple ownership in your house. Then there’s the mineral estate, which is the oil and gas. There’s essentially eminent domain for the mineral holder, where the surface owner cannot prevent you under reasonable circumstances from extracting your oil and gas.

And so they can’t say, “No, you can’t get a wellbore easement. No, you can’t get a frac pad. No, you can’t get an easement for a pipeline.” There are different university land systems that publish data around the rates for these things. But, in essence, there’s eminent domain for the oil and gas holder to extract their minerals.

Water is not protected by eminent domain, even though it could shut in oil and gas. So a rancher could literally just say, “No, you cannot cross my land, hard stop.” Or they could ask for some extravagant amount of money. When I say it’s getting harder and harder to compete with the incumbent systems, go back to that checkerboard I mentioned of the 640-acre square miles. If you have to go 50 miles and deal with 50 different landholders asking you different rates, that just shows you how difficult it is, because there’s no protection around giving you egress to get rid of that water, even though it could very literally shut in your operations.

Yeah, it’s interesting just in terms of the nuances of that legal domain and legal rights. So, yes, NIMBY rules everywhere when it’s allowed to. I wanted to close on one last point just on the CapEx, because, again, the 50-ish-percent EBITDA margins—I understand that CapEx spend for growth opportunities is spread out. When it comes to maintenance CapEx, which I know is a dirty word in this midstream infrastructure space, do you have some sense of just the maintenance costs associated with keeping infrastructure that’s dealing with very intense saltwater that would, I’m sure, corrode? Is that a heavy burden on the business?

Yeah, so you definitely have maintenance of the pumps and the pipes, and it’s a newer, nascent industry. But we’re looking, depending on the different types of equipment, at anywhere from 7 up to 28 years of useful lives. But we look at it as saying, okay, 10% to 15% of undepreciated PP&E just as a heuristic. Probably on the high side, but again, once they build out the growth, there’s really, really high free-cash-flow conversion to this business.

And then something else, going back to the growth, that I think is worth mentioning: I mentioned earlier Five Point Energy had an asset called Northwind, and Northwind is more of a traditional midstream business, but they specialize in AGI injection wells, so acid-gas injection.

The other AGI.

Yeah. So this is sour gas.

So if you look at the Delaware Basin, that eastern shelf is what's called sour gas, and it's sour because it has very high hydrogen sulfide. Hydrogen sulfide in high levels is extremely dangerous—deadly. It's that really sulfuric egg smell, but at high doses, you don't smell it at all, and it can be life-threatening.

But it's very difficult and expensive to deal with, so you've seen a lot of operators just ignore that sour gas window. Northwind, which Five Point Energy funded, went out and said, “If we build these AGIs, basically, you're setting the infrastructure for people to come up there and start really drilling in earnest.” MPLX recognized that.

They bought Northwind in what I've heard was a very aggressive, hotly contested bidding war, because people see all that growth around sour gas. WaterBridge, obviously working as a Five Point Energy portfolio company, is saying, “Well, if this growth really comes into this eastern shelf, we want to be in a position.”

So not only do they acquire a lot of surface at LandBridge, but they're developing a lot of infrastructure, so they're ready to go once those drill bits come, whether it's going to be Devon, Oxy, or Coterra. I don't want to call it de-risked, but I think there's a lot of visible growth simply from that sour gas window starting to get developed that, again, very few people are talking about. That's also probably a significant portion of that incremental CapEx and growth that I referred to earlier.

Mm.

Yeah. There seem to be some interesting, non-obvious growth angles that wouldn't have stood out to me. I guess if we just transition to how you frame a business like this, thinking about any type of valuation approach that you would use, how would you go about that? And if you want to use what you've seen in the market or anything else like that, I'm always curious about this midstream-ish business—not quite linked to oil prices, linked to production—but with a very unique profile in terms of the durability of some of the stuff.

So, putting that all together, how do you go about framing valuation?

8. WaterBridge Reframes Its Valuation

We ultimately build everything bottom-up. We look at our volume, pricing, and margin, and discount it back using a fairly conservative discount rate. However, ultimately, I think it's more discernible to look at what the comps and multiples are on a static basis and then reconcile that with your DCF.

Today, your gathering and processing peer groups—mostly natural gas, Western Midstream, MPLX, ONEOK, et cetera—tend to trade around 9 times forward EBITDA. The IPO process targeted a peer set of G&Ps with a 1-turn discount to incentivize the IPO book build. I think it did so, and then some, so it priced at the top end of the range, and they were able to upsize.

I think that pricing at a G&P multiple, while necessary because it's such a nuanced, idiosyncratic business, means you have to use something the market has familiarity with. We think the business can grow on a fairly organic basis at 15% or better for 3 to 5 years. That's expanding Kraken, expanding Speedway, and isolating the sour gas window.

You can also bolt on some M&A assets. Pilot, which is owned by Berkshire, is up for sale. They have a very interesting Midland Basin business that is legacy Diamondback, which could be bolted on. But forgetting those more aggressive bolt-ons, the organic-ish growth profile—around 15% at 8 times, with multi-decade contracts, CPI escalators, and a 50% EBITDA margin—doesn't sound right to you. It doesn't sound right to me.

So what does it sound like? It sounds like waste. You look at Casella, GFL, Waste Management, and Clean Harbors, which is one of the more industrial players. Those companies tend to be at 14 to 18 times or even more. I would argue WaterBridge has better returns on invested capital and better growth.

So if you're looking for a peer-based comp set, this is really more of an infrastructure-and-waste business than it is a midstream business. For it to trade in line with, or better than, infrastructure and waste, I think, as the market appreciates the growth, margin, and pricing, it wouldn't shock me. We try not to use multiple expansion in our base case.

Go back to the organic growth rate and add some M&A. If the company pays down debt and buys back some stock, it's pretty easy to get excited. But if you add on that rerating, which we think is more than justified, then the numbers get really compelling.

It's definitely interesting enough based on what you laid out from an organic perspective alone.

Yeah. We haven't even talked about the beneficial reuses, because you can't monetize it or even think about the economics today. But to the extent that you can clean this water and use it for agricultural purposes or even industrial uses, that adds another component that will probably be here someday, but definitely not within 12 to 18 months.

Right. Yeah, makes sense. And then, just thinking about the sensitivity of the business and where there would be the most swing in terms of outcome here, what do you hone in on in terms of the key variables, the things that matter the most?

To the extent that we're very comfortable that Permian production is going to be stable, if there's a shift, do we think it's going to shift more west into the Delaware, where there's more volume? There's also more gas opportunities, which, to the extent you believe in the AI and power-generation thesis, tie in very well to the stable, if not growing, Delaware Basin production volumes.

So that's your KPI, because as long as volume is stable, if not growing, you have the addressable market established. Then it's really: Can they capture volume? Can they push price?

The Devon agreement, the final investment decision on Speedway, and the completion of Kraken are showing us that all these cross-references to the thesis are in place. Now it's just looking at the sensitivities: What is the volume growth, at what price, and then at what margin? Those are your toggles in terms of looking at the valuation. That's where it's fairly clear-cut.

Where it gets a little bit murkier is: Are these returns on incremental invested capital as high as we thought? Is the addressable market for that as big as we thought? That's the second layer to the analysis.

That makes sense. Yeah, it's very interesting. I came into this with one subsegment of the oil market—the frac sand businesses—in mind, and I was like, “How can I separate this from frac sand?” At first, I was thinking about this in the injection mindset rather than disposal, but I think there's been plenty more to it.

As we close these conversations out, we try to hit on the lessons. As you step back and try to take away the lessons from this—from LandBridge, from TPL—what would you use as a lesson that you can take from those businesses and think about elsewhere when you're investing?

I'd say there are 3 lessons that I definitely come away from this experience with, which is now measured in a decade. One is to really develop your expertise and core competency in something. When you do that, always have your head on a swivel, looking for peripheral or adjacent opportunities.

It's easy to have blinders on and just say, “All I do is traditional infrastructure. All I do is traditional oil and gas, pipelines, and midstream.” But to Five Point's credit, they saw water, they saw sour gas, and they see data center and infrastructure. By having that core competency, it gives you a running start to jump into these other areas once you see that they're there.

Number 2 is capital efficiency. Capital-light is something that we hammer home to our team. We ask: If you were to just cut everything and go into maintenance CapEx mode, is this a good business today? Not a lot of businesses are.

So, with that notion of being capital-light from a working-capital standpoint, but also a CapEx standpoint, you tend to pay more for these businesses, but in many cases, you should. The last one is probably the ultimate capital-light real asset: land.

It's perpetual, there's optionality, it's finite, and every time I look at things with land, especially if there's a water angle, it's really easy to get excited. I always remind myself how great of an asset land is, and I wish there were a bigger opportunity set, both public and private, to scale land investing.

Yeah. Well, you guys have done an impressive job of finding the opportunities there, and it took some time for the recognition with TPL in terms of that explosion, but I think in recent years it's just been amazing. This has been a pleasure. I really enjoyed diving in. It brought me back down memory lane. Thank you for sharing the knowledge and getting into the nuance on this one. It was a pleasure.

Yeah, this was really enjoyable. Happy to come back anytime.