Flotek Industries, Inc. (FTK) Earnings Call Transcript & Summary

For fireside with John Gibson, who is Chairman and CEO of Flotek Industries who is Chairman and CEO of Flotek Industries. Flotek is a company that provides chemistry solutions to the oil and gas industry to consumers and then also has a data analytics segment, which primarily serves virtually all parts of the energy value chain. I would -- before we get started, I would like to remind people that today's discussion may include forward-looking statements and I will refer viewers to participants to Flotek's disclosures in its SEC filings and on its corporate web page under the Investors section or the Media & Presentations section for the company's most recent corporate presentation, which was posted on August 9 in connection with second quarter earnings. So with a little bit of housekeeping out of the way, John, thank you for joining us today.

Good to be here.

So as I said, Flotek reported second quarter numbers on August 9, which started to show the initial revenue contribution from the ProFrac supply agreement, which was signed in early February and went into effect on April 1. Reported revenues were $29.4 million, 128% up from the first quarter of '22 and over 220% higher than second quarter of 2021, driven by the combination of the increased business with ProFrac, but also importantly, increased business with other customers, not ProFrac or the transaction side of the business, which also increased substantially in the quarter. At the end of the -- the average fleet count with ProFrac was about 8 in the second quarter. It could be about 16 in the third quarter and probably get to somewhere in the early 30s, which is the contract amount in the first part of 2023. So John, let's start with just questions that we heard on the earnings call. You and Ryan suggest or indicated that servicing additional frac crews have gone flawlessly. Can you talk about the challenges you're overcoming in dealing with to continue to ramp up again, serve the incremental crews in the third and fourth quarter and ultimately in '23?

Of course, I will say when we said flawless, I'd probably make it asymmetric flawless, we were absolutely focused on flawless execution for ProFrac, our customer and for our transactional customers. And so on the forward side of what we were doing, I think we did a great job of getting it to the field, getting it to the customer of our customer, making sure that the ultimate producer was not impacted by the ramp-up. And so I think we did a great job with a great partner, ProFrac. However, on the back side, getting the things back to our plant, refilling them and sending them out again. we're still improving, right? So I'd say some of the margin that we will anticipate in the future is going to come from handling both sides of the transaction, both delivery then returning and sending out again. And so I'd say in Q2, we did a great job of delivering. And in Q3, we'll be both delivering and returning. And it's that logistics side of getting it back where we'll lead margin. And so that's the part where I think we're super focused on, and Ryan Ezell and his team are doing a great job on making sure that we have the full approach to that, Jeff. And so -- it's interesting and to ramp up this big. You have to remember, we went, as you stated in the beginning, we did about 19 million pounds of chemistry in 2021, and we did over 40 million pounds of chemistry in Q2. So that's twice the volume in Q2 that we did last year. We did spend money to purchase the ISOs and the in order to get the equipment and hauls to get it to location, and that's our onetime cost. And now we're actually becoming more efficient. We have in-basin delivery where we're staging it there so that as we've learned, we don't want to haul all the equipment back to Oklahoma. We want to make it a few miles instead of hundreds of miles. There's margin and all of that. So a lot going on to wrap up like this.

John, we've talked about the agreement with ProFrac on a crew basis. But it's actually a -- it's a contract to deliver a volume of chemistry to them to meet their need -- to meet needs set out in the contract. At the beginning or at the initial stages of the contract, how do volumes that you all are delivering to ProFrac for the crews that you're working on compare to what was laid out in the assumptions that were put into agreement?

Another very good question, Jeff, and 1 that is morphing or changing at the moment, when we first initiated the contract, the majority of the industry was still in trying to minimize cost. And so if you take a look at how ProFrac and Flotek estimated the volumes because you're correct, it's a volume contract. We looked at sort of what would be the minimum amount that they would use because that's all really ProFrac wanted to guarantee and I can understand that being the case. And it's way more complicated than a single number. It's actually volumes based on each basin and what fluids are needed in those basins. There's a lot of difference between the Permian and East Texas and the Eagle Ford and the Marcellus. And so it's specific numbers and the number of fleets anticipated there. And so at the current time, too long an explanation here. But at the current time, the volumes are materially above what we had originally calculated for 2 reasons. One is we did do it on a minimal basis. Number 2 is they've shifted from lowest cost to maximum AUR maximum production and IP and the least decline. And so they're beginning to worry a lot more about reservoir dynamics, and that's where Flotek excels is our [indiscernible] is designed to maximize production and maximize recovery. That's where we think we have the best solutions. And we're beginning to see that value desired by the producers. And as a result, we're seeing our higher margin components increase in each 1 of the fleets. And I think that's going to become a bigger part of the portfolio for each pad, each well as we go into 2023 and beyond because people are really focused back now on maximizing recovery and increased production on a per well basis. It's not just the cost base industry any longer.

I'm going to follow up with that. So you talked about into 2023, which is still 4 months away, but I know producers are thinking about their capital programs and activity levels far out into the future. Do you have a lot of line of sight on the types of chemicals that producers are trying to buy that you'll continue to see some mix of maybe those chemicals that you have a chance to make a higher profit on versus just the base level of friction reducer type chemicals?

We do. I mean I think we see surfactants becoming more important. Our CnF product line complex nanofluid, the need for bio side and how we use bio side. And in some cases, we may reduce the volume but increase our margin. Jeff, I mean there are some solutions where when you look at that [indiscernible] answer, you're better off to use less of something. But in that case, we may have better margin on less chemicals. So we're trying to optimize margin and as well as be the greenest chemistry company. And it's not always intuitive, it's what's the greenest, it's not just try to pump the most. It's pumped the best and get the best result.

The -- we talked about this before, but it seems to come up that the contract does contain some margin protection for the friction reducer chemicals, which I think you've described in the past has typically been a loss leader for the industry. And I guess along what we were just talking about, just has the mix of chemicals changed very much from what you thought you were signing up for in February. Maybe it's partly producer-driven like you mentioned. But is there a greater adoption of some of the chemical solutions Flotek is providing as well that's behind that?

I probably should get Ryan or James Silas, our Head of Research, to do 1 of these chats with you 1 day on just friction reducer because friction reducer or it's polyacrylamide are the bread and butter of the chemistry industry, people don't realize just how much horsepower it would be required if you didn't have the ability to reduce friction in order to get the downhole pressures that are desired, you'd lose a lot of it on the surface, it would mean having to go in and increase horsepower dramatically. So in order to reduce horsepower, you reduce friction as you begin to inject. And so friction reducer is not all the same. And so when we say friction reducer, it makes up a large portion of the portfolio, but there is numerous kinds of friction reducers and people now are becoming serious about choosing friction reducers that are prescriptive for the problem that they have. And so there's varying margin even in the prescriptive FRs, right? So we can we can have different FRs for different basins and different pads. That gives us margin expansion opportunity as well. But by and large, people are trying to sell FR in order to win the clay stabilizers, the buy sides, the surfactants. And it -- and then what we did with ProFrac was to ensure that we didn't have a huge volume that was negative to us like other people with a loss leader. So we put a fixed margin in. So the great reason that, that causes alignment is that from a margin perspective, I don't care how low the volume gets. If we can choose FRs that they can use less of, we still make a good margin on that, and it doesn't become a problem for us. So I think that's great alignment with the customer. But there's a lot of variance in it, right? There's different FRs, different margins for us there. And it has proved to be something that will be accretive to us as we go forward because we're not losing money on a day-to-day volume on FR. But don't think of it as a single product, it's varies a lot by basin, a lot by pad and a lot by reservoir.

The Flotek spends a lot of time on technology, obviously, as a chemistry company. But my understanding is you all can as go for a certain formation and help the customer design the chemical solution, which will be best suited to that formation, whether it's in West Texas or Louisiana or the Marcellus. Are you seeing more producers looking to you for those types of answers?

We do a lot of that work, Jeff. It's -- I don't want to get too technical, but in every reservoir is made up of different rocks, different petrology -- and so the chemistry that you inject is going to react differently based on the fluids that are in the rock based upon the mineralogy of the rocks, what the chemistry of the rocks are, diagenesis, which is the precipitation of material in the poor space. How are you going to interact with that? Which clays are there? Are we expanding the clays, are we trying to prevent expansion. And so in every case, you have to look at the chemistry, and you not only have to look at the chemistry, you have to look at the interaction between different chemicals that you're injecting. So I say this often [indiscernible] is much like a patient, if you were a doctor, and you're prescribing medication for it to try to make the patient better. Often, wells have many doctors looking into them, and you can have an interaction between 2 medications, it kills a patient is absolutely true in the world of chemistry. And so we have to take a look at the patient, understand what others might be prescribing for the patient, but also understand the patient, which is the reservoir and then say what is going to be in the best interest of optimizing the health of that reservoir, which would be the ultimate recovery as well as the initial production and the minimization of that decline curve.

We -- I believe on the call, you all talked about the ProFrac or revenue from the ProFrac contract in the context of roughly $500,000 to $600,000 per fleet per month. That's a relatively easy way to think about services, but can you just talk about some of the moving parts that go into how those numbers are put together?

Sure. I mean every fleet, the -- they're working directly with the producer to determine what fluids are necessary and what horsepower is required and the interaction of the reservoir. When you look at that, we're having to try to do -- and this will get better with time is how do we report to our shareholders what we're doing. And so I think an average amount of chemical per fleet, probably not a bad metric to use, but you've got to realize it varies dramatically between East Texas, the Permian, the Marcellus, the Bakken. It's every base in Delaware, you're using different volumes of chemicals at different depths and different reservoirs. And so when you look at any volume we might give you on an average basis, there's quite a lot of variance between those. And so now you have a mix issue, right? Each quarter, like talked about in many, many businesses. So it's that mix of basins and what we do, I think rather than breaking it all out, we'll probably try to stay to just chemical pounds per fleet, per month or pounds per fleet per quarter. and look at that. And you can also extrapolate those to say that those are pounds per fleet for even our transactional business, and we're growing the number of fleets there as well. And so it's a good proxy. And so -- and then the other 1 is how many fleets are we serving? And we're growing to where our goals to be a significant portion of the overall fleet count, and that would be the combination of the ProFrac fleets plus the other fleets that we're serving their competitors to ProFrac because it's not exclusive contract, we intend to be the chemistry company in oil and gas, optimizing production for every producer and every 1 of the pumping companies.

In the sense of the different basins that you produce and I know obviously, you drill a different well in each basin based on the depth and reservoir pressure and link the lateral and a whole host of inputs. Are there -- are some basins for the Flotek chemistry suite more profitable than others, just given what's needed and what operators are doing in those basins at the moment?

It's another good question. There are some reservoirs that you don't add as much value to as others, okay? And so it gets to be pretty vanilla as to what you pump. You want -- That's how you build a relationship with somebody across the whole of their fleet is making sure you're working on their vanilla fleets and they're complex fleets that have greater profitability and greater margin. But yes, there are well that just take the basics. There are customers that just take the basics, and then you have customers that are trying to optimize the EUR, the estimated ultimate recovery. You have some that are trying to minimize cost. So it's a mix. We prefer the customers that are more scientific, that are trying to base their value on recoveries and proper sustainability metrics, the reservoir really committed to green, those are the sweet spots for us, better margin, better alignment with objectives than 1 where it's vanilla and there's less concern about ESG.

You announced on August 9 in a separate press release in the earnings release that Flotek had agreed with ProFrac to provide up to 20 of your JP3 Varex analyzers. I know you all have used them on some of their equipment to help them monitor their depth of gas and so they can manage their equipment. Is this a way -- or I guess can you first talk about the timeline of deploying these units into the field?

Well, I think they're re-outfitting the units with the Verax analyzers sort of limited to the speed at which they're bringing them in and refurbishing them as they come in from the field for maintenance, R&M and then it gets sent back out. I think they intent to get them deployed as quickly as possible. So this is more of just not interfering with production operations, but getting the mole. It's a spectacular solution in the elimination of the vast majority of diesel in the field. You can take out 50% to 70% of the daily diesel use. That's a huge reduction of Co2, big cost reduction for the producers themselves. A bit of conflict because you've got some pumpers that are actually charging administrative costs on diesel. And now you're moving over to gas. And so there's a bit of a margin trade that occurs there as you switch over some of that. We're getting a bit of that margin, but we're eliminating a large amount of cost by deploying the analyzers. These analyzers are going to be, I think, have the opportunity to be prolific across everything that wants to use field gas that has variants in the BTU that needs a quality control mechanism. So that you don't damage equipment by either putting in a shut off or you regulate it through some sort of regulators so that we can normalize BTU so that you don't have the potential for damaging equipment. Nothing is worse now than damaging a piece of equipment because replacing it the lead time on that could be quite long. And you don't want to be pulling equipment out of production today for months while you're waiting on parts. And it's -- this is a critical element, switching to gas. Gas compressors, it's not just the green. It's going to be anything that's producing power in the field. I was in a conversation recently, there's a new company coming to the U.S. to do bitcoin mining and the volume of gas that they need is enormous, and they want to co-locate the bitcoin mining with stranded gas. So they can have availability to gas that will be at favorable pricing in extremely large volumes because they too want to have a green offering. And so how do you do that and supply the gas. I mean, Caterpillar is a big part of this, too. They're putting in a lot of these big fuel turbines for bitcoin mining. That's another place where JP3 could make a big difference as well.