Good morning, everyone. My name is Brady Murphy. I'm the President and Chief Executive Officer for TETRA Technologies. I'm joined today with Elijio Serrano, who's our Chief Financial Officer. We'll be giving you an update on TETRA Technologies. Our forward-looking statement. So TETRA was founded in 1981, so we've been around for over 40 years. The company started in formulating completion fluids out of brine chemistry, and that has been one of the core competencies of the company going back to its founding. In more recent years, with the advent of the unconventional oil and gas markets, we've expanded our leadership into water management, frac flowback, and sand management for the unconventionals.
But again, realizing that new sources of energy are essential to meet the future energy demand, we're leveraging our aqueous chemistry expertise, the key mineral acreage, which we'll talk about, and the global infrastructure that we've built out to expand into high-growth, low-carbon energy markets. So our geographical footprint, we're not in every oil and gas market around the world, but we are in the key markets where we want to play. Clearly, in the U.S., unconventional markets, as well as Argentina, and an emerging unconventional market in the Middle East. And on the deepwater side, we're in the Gulf of Mexico, Brazil, the North Sea, West Africa, and offshore in the Middle East as well.
The primary markets that we serve and are emerging into, of course, our traditional energy services business, which is made up of our completion fluids, production testing, flowback services, water management, and as we'll talk about, produced water desalination for produced water from the oil and gas industry. Our industrial chemicals business, going back to our original days of calcium chloride, but also merging into zinc bromide-based electrolytes, which we'll touch on, and the bromine resources that we have in Arkansas. Again, these capabilities and the resources that we have in Arkansas allow us to participate in the critical minerals industry, not only from the acreage that we have in Arkansas, which is rich in bromine and lithium, but also uniquely positioned with the oil and gas customers here in North America and around the world to extract critical minerals from produced water.
Investment highlights, so you can see the two external reporting segments that we have today, our completion fluids and water flowback are split 50/50. About 40% of our completion fluids segment is a very stable GDP type of business with our industrial chemicals business. You can see the chart on the right. We're very pleased with what we've been able to accomplish in the last few years as building a performing business that's continually improving our margins, our profitability, our returns, even during the period of COVID, which was obviously a very difficult time for the oil and gas industry. We expect to continue that progression as we move forward into the future. I think this slide highlights one of the things that's very important to our strategy as a company.
We're getting into new markets, high-growth markets, but we're doing that based on leveraging the capabilities that we have built around the company. Bromine is a great example. We use bromine today for our formulation of our brine chemistry, our completion chemistry for our oil and gas completion fluids business, where we're a leader in that market. We have been able to leverage that capability and chemistry know-how to develop a zinc bromide-based electrolyte that is a key part of the Eos Energy and future zinc bromide type of long-duration energy storage technology. Again, very high growth rates that we anticipate for that segment. On the water management side, we're one of the leaders in North America for treating produced water, recycling for frac. We're leveraging that capability to evolve into the desalination for beneficial reuse, which is a huge opportunity and need, quite frankly, for this industry.
And then we mentioned the brine assets that we have in Arkansas, again, leveraging the expertise that we have to extract minerals, in this particular case in our Arkansas acreage, lithium and bromine for servicing our growth of the future, and lithium would be a new market for us to participate in. Some recent highlights. Again, we won't go through all of these, but again, core to the strategy milestones that we are achieving. First, we secured a multi-well multi-year deepwater completion fluids project in Brazil that will be starting in the first half of 2025. We've announced the introduction of our TETRA Oasis water desalination solution. Following successful trials and wet test results, we are at the stage where we've been demonstrating pilot and commercial status with the technology and are now doing the engineering work for scaling this up for larger scale type of projects.
And we delivered our first full electrolyte for the energy storage to Eos Energy. Previously, we were just providing the zinc bromide. Our contract has expanded to include the full electrolyte, and that's a new milestone for us as well. All of these are setting us up for what is a very encouraging outlook for us in 2025. So I'll talk a little bit more about our completion fluids segment. We are known in the industry as the innovation leaders for completion fluids. I think those of you who are familiar with David Bat of Kimberlite in our industry, TRACKS, a very well-known market analyst in our industry. And his research, you can see the quotation, we stand out as the performance leader in the Gulf of Mexico.
And the reason that's important is the Gulf of Mexico is by far, in our view, the world's most complex deepwater market around the world, a combination of temperature, pressure, depth of water. So having that recognition is obviously important to us. You can see on the business segment, the revenues have come out of COVID days when we saw the market downturn, but we've done a very good job of maintaining the profitability and the margins in this segment. And we're fully expecting to start seeing some growth, both from the deepwater markets heading into the next few years, as well as the Eos Energy contributions will be shown in this segment. So the growth strategy for this segment really is around deepwater market recovery.
I think a lot of people believe that the North America shale will still grow, but certainly not at the levels that it has been the last five to 10 years. The deepwater market is one of the next areas where the additional barrels will be coming from. We've expanded incremental capacity, both on the market share wins, as I'd mentioned, as well as contract awards, and in inorganic growth, we've positioned ourselves with some inorganic growth, I should say, through some recent M&A, smaller recent M&As, but have positioned us very well in the key markets in the North Sea, again, the Gulf of Mexico and Brazil. If we look at Rystad's projections for the deepwater floater demand, you can see the period that we're in in 2024. Actually, this was published in mid-year. I don't think the rig activity reached the 133 rigs that are shown here.
I think somewhat less than that. But certainly, the growth projection is what's key here. And talking to our customers, our contracts, we see this growth coming in the next five years. It's about 40% growth in the deepwater rig activity between 2023, where we ended around 119, to the 166 in 2028. Again, we're known as the innovation leaders in this space. One of the key technologies that we have introduced is CS Neptune. We are pleased to have been awarded the 2020 Hart Energy Meritorious Award for Engineering and Innovation in our segment. We were awarded our first series of projects since COVID. Our last Neptune job was in the fourth quarter of 2019 when COVID came. A lot of those higher deepwater projects kind of came to a standstill. And around 2022, 2023, that pipeline started to move forward again.
We announced our first award in the fourth quarter, and that work will be starting in the first quarter of 2025. We've also very recently introduced TETRA X. It's really a game-changing inhibitor for corrosion inhibitor, about 35x improvement in corrosion inhibition in a downhole environment with temperatures over 300 degrees. Moving on to the water and flowback services. This segment for us was more impacted by COVID. As you can see, the revenues in 2020 dropped. We did maintain a positive cash flow and positive EBITDA during those times. Again, introducing a lot of technology into this segment has helped us increase our market share. Our EBITDA margins, now that we've gained quite a bit of share over the last few years, positioned ourselves. We're really focused going forward more on margin enhancement and returns.
We'll talk a little bit about some of the solutions that we're bringing to achieve that. Again, for us, it's now leveraging the assets and resources that we have put in place over the last few years and adding an element of automation to each of those subsegments to reduce the amount of personnel that are required, improve the margins, and also improve the operational efficiency and HSE performance for each of these segments. Our BlueLinx automation, we're about 70% implemented, allows us to reduce about 30%-40% of the personnel for these types of operations. Automated SandStorm, we're about 20% implemented, again, allowing us to reduce about 50% of the reduction under a high-pressure environment around in the red zone, so to speak. And then automated drill-out system. This is a new market entry for us, being able to eliminate about 75% of the people.
People costs in this segment are the highest cost element. So achieving these automations and these types of reductions is really key for us and a great opportunity for us. We don't see a lot of other people bringing this type of technology into this segment. So the real future growth of this segment for us is around the water desalination and extracting minerals from produced water. I'm sure those of you that follow this industry are well aware of the amount of produced water that is being produced along with the oil and gas here in North America. Permian Basin, about 8.3 billion barrels of produced water in 2024, and about 7.2 of that is disposed in saltwater disposal wells. The problem is that these disposal wells are now overpressuring, and the industry is running out of pore space to put produced water into disposal wells.
That is causing seismicity events in key parts of the Permian Basin. That has caused the Railroad Commission to come in and start restricting where operators can start to put produced water. That's causing the operators to have to build additional infrastructure to pipe it away, additional costs to truck it to other areas. But the problem is this trend is going to continue. No matter what happens to oil and gas production in North America, whether it grows like it did or not, produced water is going to continue to increase. That's just the nature of how production from these wells comes about over time. So this is a growing problem that needs a critical solution. As I mentioned, the seismicity events are really becoming a bigger issue, and it's all around overpressuring deep water or deep horizon formations.
As you can see, the trend has been continuing to increase. TETRA introduced, and again, this is something we've been working on for some time and has been a part of our core strategy, is to leverage the capabilities that we have, not only just to treat produced water for frac reuse, but to treat produced water for beneficial reuse. When I say beneficial reuse, we're talking about surface discharge application, irrigation, agriculture, industrial applications. I'm not sure we'll see drinking water, although we treat it back to drink water quality, but I don't think we'll see drinking water or produced water anytime soon. Certainly, there's plenty of applications that need water in the Permian Basin. We've been able to essentially bring an end-to-end solution to the market.
We've leveraged our pre-treatment capabilities around treating water for oil and gas for frac reuse and leveraged that to be able to bring more traditional desalination technologies to the market. For us, we have exclusively licensed two technologies, a vacuum membrane distillation technology, as well as an osmotically assisted reverse osmosis technology. Depending on the level of salinity that we run into, Permian Basin is different than Appalachia, different than South Texas, different than Powder River. So depending on that combination of constituents in the water as well as the total dissolved solids, we can marry up our pre-treatment solution with the type of membrane technology that we can bring and then the post-treatment capabilities back to the customer specifications. The reason this is so important is because obviously desalination of ocean water occurs around the world today. It's a very big market.
The problem with oil and gas produced water, it has a lot of constituents in it that are harmful to the membranes and will damage the membranes very quickly. It's not really commercially viable to use membrane technologies with produced water right out of the well. It has to be pre-treated. That's the key element that we have been able to bring to the solution. As a quick update, we did our first field pilot actually almost two years ago, two and a half years ago. We were able to get 92% of the produced water back to desalination quality, total dissolved solids from 40 parts per million to 200. That's when you look at that, that level of salinity is better than the average standing drinking water today, which is about 300 parts per million TDS.
We just recently completed a Permian Basin, which is a much higher, more higher TDS, challenging water quality back to the Railroad Commission standards, and we're able to pass a Whole Effluent Toxicity, which is really the gold standard for treating water called a WET test. And so again, pleased that we've achieved that milestone. So moving on to our low carbon energy strategy. As I mentioned, we have resources in Arkansas. The company maintained leases that are rich in bromine going back to the 1980s, to the original time that TETRA was formulating completion fluids using bromine and needed to make sure it had a security of supply through those leases. Over the years, the company was able to negotiate very favorable third-party supply contracts, so those leases were never developed.
In the last few years, we've discovered that the brine in those leases is not only rich in bromine, it's also rich in lithium. So essentially, we have partnered up with ExxonMobil, formed a unit that the Arkansas Oil and Gas Commission has approved. And we've been doing a lot of the engineering studies around that, but essentially, both bromine and lithium allow us to participate in the low carbon energy space. As I'd mentioned before, our bromine zinc bromide formulation is a key part of long-duration energy storage. EOS is a company we'll talk about that is utilizing that. The resources that we and lithium that we have published those results in terms of the resources in place, but working on the engineering for a future release of the economics of that project. This hockey stick that we see here is not a forecast.
This is an actual growth from the EIA in terms of the utility scale battery storage from 2010- 2014, about a 70% CAGR since 2020. That is the space that Eos plays in. We're very pleased with the partnership that we have with Eos. We have created a patented formulation for a high purity version of zinc bromide that we have a five-year contract for where we get to provide a minimum of 75% of their full electrolyte and essentially all of the 100% of the zinc bromide within that formulation. Coming back to the mineral discussion, again, our lease is about 40,000 acres in southwest Arkansas. I'd mentioned the Arkansas Oil and Gas Commission has approved our unit, 6,138 acres, split between 65% mineral interest for TETRA and 35% of Saltwerx, which is 100% owned by ExxonMobil.
We have an additional 35,000 gross acres where we have 100% of the mineral rights except for lithium. We signed a deal with Standard Lithium and now Equinor for the rights to produce lithium from that acreage where we will, without any investment required on our part, get a 2.5% royalty for future lithium revenues. So with the growth that we have coming both on the deep water side that we talked about, and that's our base business, our completion fluids, bromine-based fluids, as well as the Eos projections that we have, we have a significant increase in bromine demand coming in the next five years. So we have done the engineering work to look at extracting bromine from our leases. As I'd mentioned over the years, we've been successful with negotiating favorable third-party supply terms for our bromine needs.
But as we look forward, our demand increase is such that those available supply agreements are not going to be sufficient enough for us. We're going to need to have our own source of supply. We have probably 100 years' worth of bromine supply in our leases. So we are doing the engineering work now, and we've published the results of that engineering work. The feasibility study, the DFS that we've published is on our website. You can look at the details of it. It's about a $700 million net present value, 10, and a 62% IRR. It does require $270 million of capital for us to achieve that. And we'll talk a little bit about some of the options that we are looking at to phase that project as opposed to FID, a project of that size and magnitude all at once for TETRA.
But the economics are incredibly attractive and again, supporting our deepwater market growth as well as the electrolyte requirements that we have. So we talked about the $270 million investment. As I mentioned, we are looking at a phased approach for that. That really consists of a couple of things. One is a lower initial production from the bromine investment that we make, but also requires some what we'll call bridging supply agreements with the key suppliers of bromine to help us bridge from where we are today to where we have the full phase III, 75 million pounds of bromine capacity.
That's the DFS, which we published in the $270 million investment that is needed, but allows us to stage this in bites of capital that even though we're very confident we can fund the 270, we feel having some optionality is to phase that with a lower CapEx investment is prudent for us to evaluate. And we're in the process of evaluating that now. We hope to be able to announce where we are at the conclusion of this staged approach sometime in the first quarter. So with that, I'm going to turn it over to Elijio.
Thank you, Brady. We report our earnings on February 25th and have our investor call on February 26th, our Fourth Quarter Earnings Call. I won't touch on fourth quarter results, but we'll talk a little bit about what the trend has been and what we expect the next several quarters to be. Trailing 12 months revenue is $618 million, and trailing 12 months EBITDA is $101 million. Consensus for this year for 2024 revenue is $603 million, and consensus for next year for 2025 is $676 million. So we're projecting based on consensus about a 12% year-over-year growth. On an EBITDA basis, consensus for 2024 is $96.5 million, and consensus for 2025 is $124 million, about a 28% year-over-year growth. I'm not sure that you'll see many energy service companies show that kind of projection, especially with the slowdown that's been occurring on the U.S. onshore market.
Our growth over 2024 is driven essentially by four factors. Number one, Brady talked about the Neptune project that we secured in the Gulf of Mexico. Three wells, first one scheduled to begin in the first quarter. Those are very large, profitable wells. Second, as Brady also mentioned, that we picked up a significant deep water project, multi-year, multi-well in Brazil that will also impact the results this year by a significant factor. The third is that the zinc bromide battery solution, the electrolyte that we've been producing for long-duration battery storage, we anticipate the volumes to materially ramp up beginning in the second quarter and increase sequentially each quarter thereafter.
In addition, we've got the calcium chloride business that grows slightly faster than GDP, especially given our market share position to where we have a significant position in Europe, having the largest market share in Europe and second largest market share position in the United States. So even despite a continued slowdown of the U.S. onshore business that's slowing and that drilling and completion activity slows down, we expect that we see a significant year-over-year improvement. If you look at our balance sheet and how we've prepared our capital structure, even during COVID, 2020 and 2021, we generated significant free cash flow and improved our leverage ratio. We dropped debt from $189 million all the way down to $120 million, and our leverage ratio is currently 1.5x .
We've got almost $200 million of liquidity, inclusive of a delayed draw feature that we've got on a term loan that allows us to draw up to $75 million to fund our bromine projects in Arkansas. We're also sitting on $58 million of cash on hand. We don't have anything outstanding on our ABL credit facility of $100 million, and we've got a term loan that does not mature until the year 2030. Now, if you go look at the EBITDA projections of $124 million, this year we'll run somewhere in the $40 million of capital expenditures for the base business. We're running around $20 million a year of interest expense and running about $8 million a year of cash income taxes. That gives you a free cash flow capability approaching 10% free cash flow yield to determine how much of that we invest into our Arkansas project.
That's a decision that we'll make as the year progresses. So the combination of a strong balance sheet plus a growing business allows us, I think, to set ourselves up to take advantage of what Arkansas is bringing and allows us to participate in the battery storage market. In addition, we also have a significant tax loss carry forward that can offset almost $400 million of pre-tax income and almost $100 million of cash taxes. So as the business ramps up and we see that kind of profitability come from the Gulf of Mexico, we see that profitability come from the battery storage market and our calcium chloride, we're seeing a significant fall through to cash flow as a result of those tax benefits.
So if you look at everything that we've done, we've got a solid performing base business, our onshore business using desalination technology to expand into a growth market, using automation to reduce the amount of headcount and improve margins on the onshore side, a leading position in the deep water market, especially with technology such as Neptune and the growth that we're expecting that to occur, plus moving into the battery storage market, moving into the lithium market in the future, and then moving into the desalination market. We believe will open up new market opportunities that will allow us to move significantly faster than any of the industry and also move us into higher margin, higher growth opportunities. So that's a quick summary on TETRA. For those of you participating online, we've got a copy of our investor deck on the website.
For those of you in person, there's a copy of the presentation here. Brady and I will gladly take questions now.
Have you explored a joint venture to provide that mining, the bromine mining in Arkansas, or is it something you want the control of that aspect?
Yeah, for us, for bromine, we want to control our destiny as it relates to the security supply and to feed the two markets, the energy storage growth that we have, as well as the oil and gas segment. So our preference, we're not opposed to looking at joint ventures. If you look at what we've done on the lithium side for our acreage in Arkansas, the ExxonMobil JV essentially. So we're not opposed to joint ventures. But as it stands right now, we're quite confident we could fund the project, especially if we pace it and stage it a little bit differently than all at one go, where we wouldn't really need to share that value with a partner.
It's our belief also that we can do this without issuing any equity or any equity-linked securities. Either cash flow from operations or existing liquidity, we believe, can fund our project.
How capital intensive is the operation of that mine?
Actually, the upfront investment is the large majority of the CapEx. The ongoing maintenance CapEx is very small.
And also, these are not open pit mines. This is drilling wells up to 10,000 feet in depth, extracting the brine as a liquid, extracting the lithium and the bromine molecules, and then reinjecting that. So this is not open pit mining. This is simply drilling deep water wells.
Yeah. Yes, sir.
I think you mentioned part of the reason for this decision is you just can't get enough supply from your suppliers. Can you just give us an overview of what the supply demand dynamics are today in bromine into the future?
Yeah. So bromine is an interesting market. There's really three companies that collectively have 75%-80% of the bromine market. And the two primary sources of bromine that are produced today are the Dead Sea in the Middle East and the Smackover Formation in Arkansas. So our contracts are with current providers. Lanxess and Albemarle specifically are the main bromine providers in the Smackover in Arkansas. And that's the contracts, as I've mentioned, that we've been able to. The problem is they've been producing the Smackover in their areas for 50, 60 years. And the bromine concentrations are starting to drop, obviously, over that period of time. So the richness in our acreage, which is basically virgin acreage, compared to the available supply that we see coming in future years, just makes sense for us. As the market itself, it's mostly bromine is used as a fire retardant.
That's the market that consumes the lion's share of bromine. And electronics, of course, the electronics industry, as well as EV cars, are consuming about five times the amount of bromine just through the electrification of that industry as traditional vehicles. So that also is contributing to a growth side of the equation. At the same time, you've got some challenging supply issues. Yes, sir.
Is there a long-term offtake agreement or a market where you can hedge future bromine prices?
We have the Eos agreement. That's a five-year supply where we're guaranteed 75% of their volumes. We're not locked into a specific volume with them. But those are the types of agreements that we have. As far as long-term oil and gas, we have multi-year oil and gas contracts with our customers. But typically, they're not take-or-pay type arrangements. But if we got into a situation where we had excess bromine available to us in our project, we could certainly look at those types of contracts, which the current bromine suppliers do today.
When will the first lines yet to speak on Eos?
I think they're projecting the second quarter of this year. I don't want to speak for them. I think they're actually presenting Thursday?
They're presenting Thursday morning at this conference virtually.
Yeah. We've been to their facility many times. We have a very close relationship with those folks, and we see the progress. I think the first automated line, though, is due to be functioning sometime first half this year. Yeah.
You guys just talked about the 270 now. So kick it out a little bit from 280. Just 270 CapEx, you could potentially split that with ExxonMobil. Can you remind us what that potential joint venture would look like?
So.
You have $200 million of liquidity currently. Just want to make sure.
Correct.
Plus you're doing roughly $40 million of free cash flow a year on a normalized basis.
You want to cover?
Yeah. Based on $124 million of consensus EBITDA and again, taking into account capital expenditures, around $40 million for the base business, $20 million of interest expense, and give or take $8 million for cash taxes, that gives you $50-$60 million per year of free cash flow over the next two years. And the construction of the project that we're talking about is about a two-year period. So the combination of cash flow plus liquidity, we think, gets us there.
You definitely don't need to raise capital limits.
No.
At the end of $50 million.
Our intention is to avoid any equity-linked security to bring this project online, and again, the objectives of the project are twofold. Number one, give us more volumes for the oil and gas deep water market plus the battery storage market. Number two, we believe, based on all the economics and engineering studies we have done, that we can produce bromine significantly cheaper than we can buy it in the market today. And those two give us a cash flow that we think this $270 million project, we've estimated EBITDA of around $100 million, which is less than a three-year payback.
With a potential partnership with Exxon, would the cost be more like $200 million?
No, that 270 actually is for the bromine. Yeah, the Exxon partnership is for strictly lithium.
Oh, okay.
We haven't published any financials on the lithium side yet. The 270 is just for the bromine. That's our portion of the bromine.
That's correct.
Yeah.
It doesn't include any of the lithium potential partners. Okay.
None of the lithium is included in that.
Okay. Thank you.
Now, having said that, the upstream portion, because we've got to drill wells to produce that same investment we're making in bromine, will all be done by the time we get to the lithium, because the lithium is in the brine already that we'll be producing. So there's no upstream investment required for the lithium once we do the bromine. That's a real financial benefit that we have two critical minerals in the same brine flow.
Also just north of us, Standard Lithium and Equinor have formed the partnership so that they can produce bromine or lithium from acreage just north of us. Anything that they bring to the market so that they can get to the lithium, they by default are extracting the bromine, which is all our bromine. That gives us incremental volumes above and beyond what we can get from the $270 million investment without any upstream CapEx on our side.
The cost of technical capability to get lithium out of the brine that we don't need this year?
Yeah. So if you follow the.
Cost of that for lithium.
Yeah. Direct lithium extraction technology has evolved quite a bit over the last couple of years. I think when you look at hard rock mining, I think you'll typically see OpEx costs in the $8,000-$10,000 per metric ton range. Our expectation for the DLE technologies that we've been exploring, we believe, will be sub $5,000 a metric ton. So there'll be a real cost advantage on the OpEx side from our perspective on the direct lithium extraction technology.
One more question. Just one short slowing down a little bit. Your offshore business with Brazil and the three projects you won, big project. You haven't done anything like that in a long time. Congratulations.
Thank you.
Do you feel like $50 million-$60 million of potential free cash flow over the next couple of years is doable, even with onshore slowing down a bit?
Yeah. Our assumption is that onshore is flat at least through 2025. It's going to be really based on what happens with the global economy. But we're not expecting any onshore growth to be able to generate the type of cash flows or EBITDAs that are in consensus.
You're assuming flat versus this year already with the decline already happening?
That's correct.
Thank you.
Yep.
For the treatment of produced water as well, it seems like the break-even for the producer to go that route would be whatever the cost would be to transport it or build a pipeline.
To truck it. That's the right way to think about it. Short term, keep in mind, you can truck it to an adjacent location, say, $2-$4 a barrel. But eventually, you're going to fill that pore space up as well. This problem just keeps compounding itself from a cost perspective, the further distance you have to go. Pipelines, I mean, they could be a significant $50 million types of investment. It's a CapEx issue.
Is there a way to frame what your treatment cost is relative to that?
We are projecting to be in the $2-$2.50 a barrel processing fee to desalinate water.
That's revenue, not cost.
Yeah, that's revenue.