Flotek Industries, Inc. (NYSE:FTK)
Analyst/Investor Day Conference Call
July 29, 2013 7:30 am ET
John W. Chisholm - Chairman, Chief Executive Officer and President
Carla Schulz Hardy - Director, Member of Executive Compensation Committee and Member of Corporate Governance & Nominating Committee
Marc Kevin Fisher - Executive Vice President of Global Business Development
Glenn S. Penny - Director of Technology
John S. Reiland - Director, Chairman of Audit Committee, Member of Corporate Governance & Nominating Committee and Member of Executive Compensation Committee
H. Richard Walton - Chief Financial Officer, Chief Accounting Officer and Executive Vice President
Steven A. Reeves - Executive Vice President of Operations
Josh Snively - President
So, a formal good morning to you all. I'm Chris Edmonds, Senior Director of Corporate Finance and Strategy for Flotek. And since this is being webcast, I get the distinct privilege of reading the following:
Certain statements and information included in this presentation constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based on certain assumptions and analyses made by the company’s management in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances.
These statements involve known and unknown risks and uncertainties, some of which are outlined in the company’s most recent 10-K and subsequent 10-Qs, which may cause the actual performance of Flotek to be materially different from any future results expressed or implied in this presentation and the forward-looking statements. Flotek undertakes no obligation to update any of its forward-looking statements for any reason.
Question? Didn't think so.
So, well, good morning, and welcome to Florida. We have a pretty packed agenda this morning, and we're delighted you all came to Disney World for a summer vacation. So let me just walk through the schedule very quickly.
We'll start with an overview of Flotek and 3 announcements we made this morning. Josh Snively of Florida Chemical will introduce Florida Chemical to you all. Glenn Penny, Kevin Fisher and Jim Crafton will talk about CnF and other advanced chemistry initiatives and the environmental impact and stewardship we believe we espoused in those chemistries. We'll review other businesses and our capital plan today with Steve Reeves, and then we'll summarize and have a question-and-answer discussion.
We plan to leave here on the bus, for those of you going to Winter Haven at 11. Bring your bags with you if you're flying out this afternoon, as we will return you after the plant tour and lunch in Winter Haven directly to the Orlando Airport in time for the flights that you have indicated to us you're on. We'll be back at the airport no later than 3:30, which gives you plenty of time to make a 4:30 or later flight. So that is the schedule.
Let me introduce the folks from Flotek who are here. And if I miss someone -- I don't think I will. All of you know John Chisholm, Flotek's Chairman, President and Chief Executive Officer. In the front row, in the pumpkin-colored shirt, Steve Reeves, the Executive Vice President of Operations. Rich Walton, only accountant who wore a jacket in Orlando in July.
Kevin Fisher. Kevin's in back. He's the Executive Vice President, Global Business Development. Josh Snively, your first sort of big introduction on a public forum as the President of Florida Chemical, a native Floridian, is that right?
A native Floridian, and you'll get to know a lot more about Josh and get to know Josh a lot better here in a few minutes. Glenn Penny, who's our Chief Technology Officer. Myself. Jim Crafton, he's sitting in the back. I guess he's not an accountant. I guess engineers wear jackets as well. Jim is the President of Performance Sciences, which is a scientific adviser to Flotek. He's done a lot of the empirical data analysis on CnF, and he'll walk us through his findings. And then finally, in the back, in the blue and light-striped golf shirt, is Jay Portwood. Jay is the President of Eclipse IOR Services, which we announced this morning that we're in a Letter of Intent to acquire. And we'll talk a little bit more about that here in a minute, but we're very excited about that. And Jay, we're delighted you're here.
This morning, we put 3 press releases out, and I just want to bring your attention to them. If you don't have all 3 of them, they're on the registration table right outside of the room. First, we released preliminary second quarter data. I'm not going to go into the details right now, John will talk about that here in a bit, but we did announce what we believe is the second best quarter for Flotek classic in its history. So that's Flotek without Florida Chemical. You put Florida Chemical in that number and the number looks obviously even better.
We also released an analysis on Friday in an 8-K and delineated our new segment reporting in that same press release this morning. We will add a fourth segment, which Rich will talk about, which will capture the nonenergy chemical technology's flavor and fragrance and the like that we've talked about that's so important to Florida Chemical's business.
We also announced, as I said a minute ago, a Letter of Intent to acquire Eclipse IOR Services, a polymer-based EOR/IOR company. They're one of the leaders in polymer injections and EOR and IOR systems. They work for significant EOR/IOR customers such as Kinder Morgan, Occidental, Apache, and Jay will be around to discuss that. Jay won't be making a formal presentation as we just concluded the negotiations and signed the Letter of Intent yesterday, but he is around to discuss and we'll be talking more about that as we complete the diligence and close that deal here in the coming weeks.
We also finally released a press release that indicated that we have entered into a research agreement with Texas A&M University to look at the impact of nanotechnology and nanotechnology surfactants on oil and gas flow and unconventional reservoirs. Kevin is going to talk a little bit about that, as is Glen, and we'll be happy to talk more about that as well.
So finally, we announced 2 additions to the leadership team today: Rob Schmitz, who is joining us as our Corporate Controller; and Tom, and I'm going to screw this up, McGuigan -- is that right? It's the first time I've probably made it -- is joining our team as an executive salesperson. Tom was most recently at Carbo Ceramics and has a great deal of solid relationships in a deep Rolodex, with C-level people who we believe can help us advance the ball in terms of marketing direct to those end users of CnF and other products.
So again, thank you all for being here. With that, I'd like to turn it over to John Chisholm, Flotek's Chairman, President and CEO, to discuss the current state of Flotek. John?
John W. Chisholm
Thanks, Chris. It was not intent but oversight. One person Chris forgot to call out was Carla Hardy, who's dad was the creator of Florida Chemical. She was the chairwoman of Florida -- I mean, yes, Florida Chemical. She's on the Flotek board. She certainly brought down the age demographics and jazzed up the attracts demographics. But beyond that, she has the chance to help continue the legacy of Florida Chemical inside Flotek, which we think is pretty important. So...
Carla Schulz Hardy
It's all good.
John W. Chisholm
It's great to see this nearly standing room only. When we had the first one of these in the fall of 2011, we had to nearly kidnap 10 people to get them in the door. Paul was there, a few others, and then we had to lock the door to make sure they didn't leave. So the fact we have 3 times as many just 2 years later is really kind of special.
Here's what we want to try to accomplish, or we will accomplish before you guys get back on the plane at 3:30, is we'll provide an update on the state of Flotek, and you're going to really know a lot about Florida Chemical before you leave the great state of Florida, between Josh giving you the overview and then seeing the facility at Winter Haven.
As Chris mentioned, Rich will walk you through some of the accounting machinations that we've gone through to try to create the best transparency we can for you as to how Florida Chemical blended inside Flotek works. And as we mentioned, we'll have a couple of topics about the environmentally friendly suite of products that not only are happening now but will continue to happen. And Dr. Jim Crafton will provide some current data as to just why the complex nanofluid has the chance to really impact the economic performance of folks' wells.
Additional innovative technologies at Flotek, we've got 2 research efforts that are individually focused but collectively joined. The Florida Chemical effort is environmentally innovative. That's their focus. The Flotek is practical applications. Both will be headed up in the Woodlands. Josh will be the guy that has the responsibility to direct that effort in terms of making sure we've got the best and brightest on both efforts, working in an effort to try to blend all that into value for you, our shareholders. And then at the end, I'll provide an update on what's next for Flotek as we see it.
If there ever was a slide that shows the story, this is it. And -- but slides, really, that's -- all they do is show a story. You're in for a rare treat today because the folks that really make it all run are here. It's all about the people. You're going to meet the people that make Flotek run.
I was visiting with a gentleman last night from Capital One. He asked me how much of my time do I spend running the business -- hope this doesn't cause any harm or alarm -- it's actually the smallest part of what I do, and that's because, when you leave here today, you'll understand why I don't have to run it. In fact, I'd be probably the last guy to run it. We've got really smart people involved in the sales, in the accounting, in the operations, in the technology, and that's the truth I'll leave with [ph].
Those people are the reason that graph goes the way it goes. My job is to create the environment and the culture where they've got a chance to do more at Flotek than they could anywhere else, and I think that slide speaks for itself.
The next slide really kind of talks about where Flotek has been from 2010 to '12 and then to '13. Some of you remember those dark days in March of 2010, the stock price was $0.97, market cap at $32 million. Market cap now is $1 billion. And you can see that, compared to statistics, is Flotek against the New York Stock Exchange, the OSX and our peer group, something we've worked very hard for in this journey, something that we understand once we were at this point. We know we're only as good as what we've done and looking forward to continuing to put up graphs like this in the future.
Folks have been wondering, why Florida chemical?" It started back in a quest of 2007 and 2008 when I was a Director at Flotek, and I urged the management at that time to reach out to Florida Chemical because I was really concerned that someone could do an in-run on Flotek, get a hold of Florida Chemical because the d-limonene product is just the key kernel to the Complex Nanofluid suite of chemicals. And it didn't happen then. A lot of you are familiar with the financial tsunami that engulfs not only most of the industry but certainly Flotek in '08 and '09, and we went from trying to figure out kind of, I'd say halfheartedly, how to acquire Florida Chemical back in '07, '08 to where we had a rather fateful meeting in the late summer of 2009 when Josh Snively came to Houston. We owed Florida Chemical about $2.5 million. His auditors and his directors said, "Have you lost your mind to sell another gallon of d-limonene to Flotek?" And Josh and I were able to figure out a way that he could go back to them and say, "No. We need to keep selling because if we don't, the whole thing will unravel." And that evolved to even a tighter coupling of the relationship. As you can see up here, this is what we get with Florida Chemical.
Some people look at it as a vertical integration, and that's true in that we now have 2 additional blending facilities. We've got a secure source of terpene, d-limonene. They are the world's biggest refiner of citrus oil, and we're going to have a connected supply chain. But where the real value is, with the whole movement with Florida Chemical, as all of you know, this industry is moving more environmental. It's being pushed that way. It's being pulled that way. We can't tell you when it's really going to happen, whether it's 6 months from now or a year from now. But when it does happen, the technology of Florida Chemical blended with Flotek's current capability will be something special, we believe.
So in terms of our initiatives here, international growth is pretty key to us, Middle East in particular, although we've reshaped the Canadian effort. We consider Canada international. We've had some questions about the status of where we are in Oman, and I'll just talk about that for a second. This arrangement, this business agreement, is to set the stage not for 1 year, not for 2 years, but for the next 10 years and beyond, and we are going to do it exactly right.
It has to do with how land is being leased from the Omani government. It has to do -- how the construction of the facility will be done in such a way that we can minimize the amount of capital in terms of creating the best return for you, our shareholders. I think the word of the day is I'd ask you all just to hang lose and be patient. We are not going to rush into an agreement in a way just to satisfy folks who are saying, "Why haven't you got it done by now?" And just -- like I say, it's a very important move. All the data we can see tells us in terms of what the increase in activity will be in the Middle East. And like I say, we're going to do it just right.
EOR, you've heard us talk about it. The opportunity was Jay Portwood presented itself. We started visiting with him in February. Many of the same clients that we work with now, the Kinder Morgans, the Denburys, the Newfields, also interact with him. In fact, Glenn Penny was one of the prime advocates of trying to figure out a way that we could give EOGA inside Flotek. So there's going to be a lot of synergy with growth. You guys have had a chance to read the press release this morning in terms of the current run rate. And it may not appear to be that significant of a transaction, and -- for those of you that know the Flotek story back in 2001, we've got our hands on the technology, the patent, that became the Complex Nanofluid for $100,000 and some Flotek stock. So you never really know, when you make a transaction like this that's a bolt-on technology, how impactful it can be. But we know that it will be accretive early on because of the way we are able to structure the arrangement. And Jay, like the Florida Chemical folks, are taking a portion of the transaction in Flotek stock, which we think is meaningful to you, shareholders, that they're certainly relying a part of their future on the performance of Flotek.
I've talked a little bit about research and development. We're actually meeting with the building people this week, that we will construct a new combined research facility in the Woodlands, just north of Houston, to try to give us the best efficiency, to give us the best facility for client interaction and client tours. We're targeting about a 10-month from start to finish before that facility will be completed. And the environmental technologies, clearly, the opportunity there -- we think it speaks for itself. There's a host of products that are currently used in the oilfield that are going to be banned. And if they're not banned, they're going to be so publicly frowned upon, it's like being banned. And our challenge, when there lies the opportunity, is to use the technology from the citrus oil with Josh and his guys and figure out how we can put that in, in some cases with Complex Nanofluid and in some cases just completely breakthrough technology. This isn't about enhancing what we have, it's about breakthrough technology. It's about how you can take benzene or toluene out of a particular product and insert d-limonene or some other version of the terpene molecule into that and make it environmentally and sustainable. So that's where we feel like the initiatives are for 2013 and '14.
When we were looking through the slides yesterday, you'll find out that the person who has the fewest amount of slides is me. That's the way it should be because the guys that you're about to see are really the ones that can tell the story, starting up with our good man, Josh Snively, and he'll give you the overview on Florida Chemical.
Thank you, John. Good morning. The great thing about being in Florida is Disney World. So when you have these kind of events, you tend to get a lot of attention, a lot of good attendance. So we're glad you're here. I'm trying to help you understand who and what Florida Chemical is and how we play into the Flotek picture.
Florida Chemical Company, we're the largest processor of citrus oils in the world. We have the capacity to process over 200,000 kilograms of citrus oil a day. That is equivalent to the world's supply of citrus oils. Right now, we're running about a third of the citrus crop, comes through our plant. We have a global, diversified supply stream, so wherever citrus is processed and the juice, oil is collected. That raw oil we buy, whether it's Florida, whether it's Brazil, whether it's Costa Rica, Mexico, Spain, all over the world, we're bringing those raw materials into Florida and through vacuum distillation, we extract the highest and best value out of that raw material stream over anyone else in the world.
So in summary, our strength is our critical mass of volume that produces very large volumes of citrus terpenes, which have great efficacy and different solvent applications, specifically oil and gas. And also, we produce very large volumes of flavor and fragrance compounds.
In addition, we have expanded our portfolio of products to go beyond the citrus molecule, and we look at other natural bio-based-derived chemicals that have different efficacy in solvent applications or chemical applications around the world. We sell predominantly -- I'd say, 80% domestically. And then depending on the year, between 20% to 30% would go export. We've enjoyed a 15-year relationship with Flotek. As John indicated earlier, it's been a wonderful journey. We've been through the good times together. We've been through the bad times together, and it just made all the sense in the world for us to come together and combine our 2 companies.
In 1942, Florida Chemical was founded as a molasses company by Carla's father and grandfather. At the time, there was a waste stream that was polluting the environment. So from the very onset of Florida Chemical Company, environmentalism and stewardship were core -- was core to who and what we are. And that continues today. That waste stream, they turned into molasses and from molasses to alcohol. Now that was the original founding principle of the company -- product of the company. As that venture winded down, the molasses industry fell on hard times, the equipment was disassembled and it was reassembled in different juice plants around the world as the frozen concentrate orange juice industry expanded.
So what they did is they started this molasses company, made alcohol. That went south, took that equipment and installed it in juice plants around the world to collect, at that time, d-limonene, which was the key raw material for the company. The molecule really had never been commercialized, and they turned that into a viable product for the resin industries, and from resin industries to solvent industries, as well as perfumes and other markets.
As you look toward the 1960s and '80s, it was all about market penetration. We took Florida Chemical from just very few markets, so expanding that marketplace across the U.S. and the globe. And our company's name, Florida Chemical, became synonymous with d-limonene in global markets. So as you had researchers around the world who are working with this wonderful molecule, were transferred to different companies and our name and our demand for our product continued to spread.
In the 1990s, we had some real nice help from the government. The Montreal Protocol, the Clean Air Water Act forced companies to change the chemistries that they were using. So we watched the circuit board industry and other critical cleaning industries be forced out of CFCs because of the damage that they created to the upper ozone atmosphere. That was a direct replacement for our -- or our products were a direct replacement for those CFCs. Hence, our marketplace began to expand dramatically in the 1990s.
In 2001, we had all this volume coming in but we were processing outside of our company. And we had focused more on market development rather than our manufacturing or technological aspects. So we changed our strategy and decided to go back to our roots, which Carla's father had started, which was innovation and technology.
So we built an R&D center in Winter Haven in 2003. And then a year after that, after we had collected our data and designed our stills for manufacturing, we've put -- we've returned the manufacturing of citrus oils to Florida Chemical in 2004. And in 2006, we expanded that capacity.
A big growth market for Florida Chemical was oil and gas. As we looked at our business, we decided to expand into the Houston market with a secondary facility. That allowed us to bifurcate our business out of food and flavor and then chemical on the other side, of which oil and gas was the fastest growing market for us. Now that became operational in 2011.
And then at the end of 2011 and '12, we expanded Waller's tank farm and blending capabilities, and we also doubled the capacity of our distillation in Winter Haven. So that's kind of our summary, obviously with a nice bow of Flotek acquiring us in May of 2003 (sic) [ 2013 ].
Our research and development. Again, we've had 15 years with Flotek. What we looked at going forward and part of the synergies of the acquisition was the R&D activities. Our ability to produce environmental innovation, new products, combined with Flotek's ability for applications in oil and gas made a tremendous amount of sense. We worked very, very closely together over the years, but there was always a small degree of separation because we were different entities and we just didn't share all of our proprietary knowledge, which, in effect, slowed down the development process. They had their ideas, we had their ideas. We shared some, but we weren't sharing all.
So we got really excited on the acquisition about bringing that together. As John indicated, we will build -- we'll be building a world-class research and development center in Houston. It will focus obviously on oil and gas. We will have a bio-based innovations group, together with an applications group. We will also continue to focus on our other industrial and consumer-staple specialty chemical markets to fulfill those needs for margins.
And then our flavor development will continue to happen in Florida, which you'll get a chance to see that today. You'll get to meet Jon Leonard, who runs that operation for us, probably one of the top-5 citrus chemists in the world. Very, very bright young man.
As far as our key innovations outside of the CnF products, John had mentioned BTEX replacements. BTEX compounds are unfriendly to the environment. They're not safe for people. And our terpene chemistries that we've develop through different cuts from our still have excellent utility and numerous applications in oil and gas. Whether it's paraffins, whether it's asphaltenes, wellbore cleaners, rig washes, pipe dope removers, the applications are endless, including refinery cleanings. There's a lot of different chemistries we can use here, and our effort is to provide better chemical solutions to the oil and gas industry, with a primary focus on the front end being the BTEX compounds.
This slide pretty much says it all. We have sold our product over the years, the primary product being the terpene molecule, because it works. It's extremely effective. And then -- oh, yes, by the way, it happens to be green. Well, that environment is starting to shift a little bit as public awareness and pressure from the legislative arena is forcing companies to consider what they're doing, how they're doing it, and there are better solutions.
This chart is pretty much a slam dunk when you compare the citrus terpenes to the toluene and xylene molecules. If you had the preference to use either of these products, knowing that the efficacy is as good or even better with the citrus terpenes, you would be foolish not to go with the citrus terpenes. Are the citrus terpenes more expensive? Yes, they are slightly more expensive. But what is the contingent liability of handling these other products? You have one still by wellhead. You contaminate one river or you endanger one person's life, and then that cost is negligible. And if anything else, it becomes much cheaper very quick.
But as you can see the citrus terpene's GRAS rating, you may not be familiar with that term, that is Generally Recognized As Safe, which means these products can be used in food applications. If you had orange juice in there this morning, you had some citrus terpenes for breakfast. So thank you very much for your patronage of our products.
Outside of the oil and gas, these are some names I think most of you will recognize. We provide some diversification opportunities for Flotek and the flavor and fragrance markets specifically. Every glass of orange juice, the Coca-Cola on the back shelf, Pepsis, a lot of flavored alcohols, candies, ice creams, sherbets, consumes citrus oils as a value carrier.
If you drank orange juice without any oil added back to it, it would be sugar water. There would be no flavor, taste to it at all.
So what we do with our processing is you have the strength coming in, 90% of that volume goes in the terpene category for various industrial applications, 10% of that volume we distill in the high-value compounds to service these markets and these companies. So that provides a nice expansion for Flotek when you look at their current portfolio. It adds margins to our business and it also gives us the ability to extract the highest and most value out of that raw material stream, which is one of our competitive advantages in the marketplace.
When we look at the flavor and fragrance market, that's an $18 billion to $20 billion market with steady growth. It is less volatile, it's less cyclical, so it's a market that we enjoy and we intend to continue to participate in.
I think that's pretty much all we have. So, okay, I hope you understand who Florida Chemical is. We look forward to having you at the facility this afternoon. And you will be able to ask more questions, you'll be able to touch and feel and get a tangible aspect of the company, as well as the products that we perform.
And now, I think Kevin is going to help us understand CnFs.
Marc Kevin Fisher
Good morning, and welcome to Florida. I'm going to present a little bit on how we approach our clients to help them deal with the challenge of producing oil and gas from very low-quality, low-permeability reservoirs. I'll show you a little bit of how the Complex nano-Fluids can assist in the fluid recovery from these low quality rocks.
So -- and I think we've been over much of this before but just to sort of reiterate some of the things that you get from the use of Complex nano-Fluid, one, is to reduce interfacial tension. Interfacial tension is the tension at the contact between 2 fluids. So the fluids could be oil, water or oil, gas or water, gas. So as that contact, that interface between fluids, we're going to lower the tension to allow those fluids to move more easily.
There is also a surface tension that has to do with the contact of a fluid with the rock or with any sort of surfaces downhole to ease that tension so the fluid will become more mobile. When you think about interfacial and surface tension, think of when you wax your car and a bead of water falls on top of that wax, and you get that perfectly round bead there. That's a high interfacial tension, that's the cause of it to be round and a low interfacial tension would allow it to spread and then flatten out. So before I think about that, you'll see a picture that I think will help bring that into focus for you.
We're using capillary pressure. Capillary pressure, think about that as sort of the back pressure that is preventing that oil or gas or water from flowing out of the formation and into the fracture. These small pore throats act like capillary tubes and they have a pressure associated with them. You have to overcome that pressure in order to get flow through these capillaries out there. And CnF helps to lower that capillary pressure so you'll get more flow of the same pressure or said in another way, you can get the same flow at lower drawdown pressure.
Increasing load recovery. When we frac wells today, we put an incredible amount of water and sand and some chemical into those fracs. And you have to remove some of that water in order to allow the oil and gas to flow. The water impedes -- the water that you put in the ground during that frac job impedes the flow of the hydrocarbons. So lowering the water saturation, removing that load water helps to produce more oil and gas and CnF does that, proves the action and producing these interfacial tensions.
And improving hydrocarbon mobility. That's more of a wettability issue. When you think about the pore spaces in the formation there, we're trying to flow oil out of these pore spaces. If you can change the wettability of that rock, if you can make it water wet through low-contact angle and spreading of that water, then the water repels the oil, the oil flows out more readily. If the rock is oil wet, it grabs that oil and then it won't allow it to flow through the rocks. So if you can change the wettability, you can improve the mobility to the oil through that rock.
These last 2 bullets here, you're going to see some really good data from Jim Crafton here in a few minutes after talking about how CnFs can help protect against shut-ins. They're the persistent effect of CnFs. Unlike conventional surfactants that are spent and basically plated out and they've done their job within a few hours after pumping a frac job. The CnF is going to last for months, maybe even for years, and improving the flow of the fluids through those reservoirs and in doing so, it helps protect that reservoir against unexpected or expected shut-ins that often damage the fracs. And when we talk about a value multiplier, I think there was sort of 1 plus 1 is, 2 hopefully, out there. The application of CnF, along with higher-quality proppants, you get more uplift than either of the 2 combined would allow you to have. So you can sort of get a multiplicative improvement in performance when you combine CnF with the high-quality proppants, and you'll see a little bit of this from Jim as well.
I tell Chris this was my absolute favorite slide to show an audience in the oilfield out there, I hope you'll agree. It came from George King, who was the fracturing technology advisor for Apache Corporation. And It's a series of photomicrographs showing oil moving through the Monterey shale, the low permeability, unconventional resource in California out here.
And I won't go through each of these but if you look at the top left up here, what it's showing is oil coming out of a very small pore space and then to the larger space. So if you look at the size of that droplet of oil, that's amalgamated there versus the pore throat that it's passing through, you can see that's not a trivial easy process to get oil out of that type rock there.
On the top right over there, it's showing a little stream of oil trying to migrate through one of these little channels, one of these little pore spaces to get back to a fracture, for instance. And you can see, if we can do something there to mitigate the interfacial tension, we can make that drop bit of oil spread more readily and move through that pore space then we're going to create a higher productivity from those wells.
If you think about what oil companies and service companies have done to date, they've done a magnificent job in learning how to plumb the reservoir. They can drill that well as long as you want it, they can place a whole lot of fracs along that wellbore there. But when you get down to sort of a microscopic reservoir level detailed out there, it's a challenge to get the oil from that tight rock into the fracture that they've created and loading that interfacial tension, changing the contact angle in the reservoir to allow the oil to flow more freely, is what it's all about.
I mentioned earlier about getting more load water back. The load water just gets in the way of this oil or this gas coming through the rock. I want you to think about one more thing. So CnF really sort of made its name and stayed in the dry gas business out there. And what CnF did very simply with the dry gas reservoirs out there, is that they got that frac water out of the way. If you got molecules of gas coming through that formation and you've got these pores all full of water, you can imagine it's hard to get the gas through all of that. And gas molecules are small. Methane is 1 carbon atom and 4 hydrogen atoms.
And we start thinking about oil, oil starts -- liquids start with at least 5 carbon atoms and go up to maybe 20 carbon atoms for a light oil. When you start getting asphaltenes and things like that, you can see 200 carbon atoms. So these molecules of oil get very large and we're trying to squeeze in things from very small pore throat. But CnF, just like with -- in the dry gas where it gets water out of the way for sure, it also lowers these surface tensions to allow that oil to flow through more readily. And then the solvency, as Josh talked about, having a solvent that can act on that oil, scrub the oil off of the surface of the rock. Alcohol is going to thin that oil, and you get a lot of additional improvement from the chemistry in the CnF that you never see from the surfactant.
And we've talked about this with apologies to our friends at Snapple, but CnF is really made from the best stuff on earth. We start with surfactants. Some of our favorite surfactants that we use, and we use a number of different surfactants packages and the various CnFs are coconut-based. Our solvent is d-limonene, it's a citrus oil that we talk about here. We used alcohol, it's usually ethanol or isopropanol in there. A lot of water and then when we're working on oil reservoirs, some environmentally-friendly demulsifiers that are also made for us from Florida Chemical here. So we've got a lot of very environmentally-friendly components in the CnF.
When you look at the scorecards that the service companies, that the operators have developed in various industries, it proves that developed and scoring chemicals are ranked amongst the cleanest, greenest that are available in the industry today out there.
Let me talk just a second about the CnF molecule here. As the CnF micelles, as we call it, is a bunch of surfactant micelles that look kind of like a sperm, there's the head and there's the tail. The head is, hydrophilic, it likes water. The tail is lipophilic, it likes fat, it likes oil. And they cluster in these micelles with the head -- with the water-loving head facing out, the tail's kind of sticking together because they like each other and bonding there. So that would be a conventional surfactant. The problem is that there's a pretty weak bond amongst the tail. But CnF does for you, it starts off with a droplet, with a nano droplet of the citrus oil and then those tails have a stronger attraction to that. That holds that micelle together better so it doesn't disperse, it doesn't stick to the rock and it doesn't shock, staying right there at the leading interface between the fluids that lower that interfacial tension. So kind of in a nutshell, that's a big advantage of the CnF over conventional surfactants. Instead of breaking apart as easily, it's more persistent on reservoirs, it's not as likely to plate out and spend themselves sticking to the rock.
This is kind of an example of one of the challenges. It's a slide that was given us for use by Range Resources and it's a Marcellus pore throat. And at total microscope levels here, that pore throat is about 300 nanometers in diameter across there. And you might have trouble from the back of the room seeing, but those little green dots you're seeing there to scale are the CnF nano-droplets inside that pore throat. So they're very small relative to even a small pore in this reservoir out here. And so these things can migrate, as long as there's connectivity. In fact, some distance away from the fracture and into the rock, all along, lowering that surface tension, all along, dropping off the terpenes and the solvents to clean the oil and to change the wettability and the flow pattern through that reservoir.
When you look at conventional surfactants, they are also very small, similar in size to the nano-droplets but they like to stick together and form films. Soap films, that's what surfactants do. And those films can be a thousand times larger than the nano-droplets that we start with, with the terpenes that don't bond together. And in fact, they can sort of film over or cover over these pore throats and never enter the formation here. They're only going to stay in the larger areas and they're going to stick and plate out with the rock and not stay with the fluid, which is where you want them. So a big benefit from CnF and a big difference between surfactants. So we like to say, CnF is not just a surfactant.
I'm definitely not going to read all of these points here but this is a little ad that we've put together talking about CnF and our environmental stewardship and what is not in CnF. And we don't have any of these hazard, we are not subject to any of these regulatory issues that other surfactants and other chemicals use in the simulation procedure or except that's as green as you can be. When you think about this, think about other green movements in your life out here. I know for a fact that my laundry soap today doesn't work as well as it did when it had phosphates in it, back in the day. Recently, they've changed your dishwasher detergent, you noticed it doesn't work as well anymore. Think about termite treatments. 20 years ago, when you treated a house for termites, you never had to do it again. It was a one and done deal. Today, you're going to be doing it annually or at least every few years because the greener chemistry typically is not as effective as what it replaced when they took the bad actors out of the chemicals. CnF is one of the exceptions that I can think of that -- it's green and it's very, very effective. So we like to say we can be green and great.
This is just a little teaser to sort of leave you with. And Jim's going to show you some data in a few minutes on 500 wells or so. Looking at CnF versus non-CnF, and looking at the production uplift given by CnF, and we've not only postulated but we've seen our clients put it into practice in the field, that in many cases, you're able to pump smaller frac jobs and get the same or better performance uplifts. So when you think about smaller frac jobs, what are some of the benefits of that? Smaller footprint on location, you don't have to tear up as much dirt to get the frac equipment and water and sand storage bench out there. You got less water to manage in throwback if you pump less water on the frac job out there. You've got less trucks hauling up and down the road, delivering all of the sand, water, proppant to location out there. You've got a lot of less risk to the public because of the lack of all that transportation out there. So there are just numerous environmental benefits in running something that produces, that allows you to produce more oil back with potentially smaller jobs. With that, I'll turn it over to Glen.
Okay. But before we do that, we're about 10 minutes ahead of schedule, so let's take a quick 5-minute. Coffee's in the back where you could refill your cup of coffee, and stretch. And we will reconvene here at 8:20 or 8:25. For those of you on the webcast, we'll take a 5-minute break and begin again at 8:25 Eastern Time.
All right. To stay on schedule with the webcast, we'll get started here again. So I think at dinner last night, I introduced him as the grandfather of CnF because he's too old to be just the father. But in all seriousness, a large part of current-day Flotek is the result of the ingenuity and exceptional chemistry acumen that our next presenter has. And that's Glenn Penny who is really is the father of CnF and several other chemistries that are in the Flotek portfolio. And so Glen's going to walk you through a more scientific journey of what CnF does, not only in primary completions but elsewhere. And he's been an important part of the team for some time and a good friend of John for some time. So Glen, take it away.
Glenn S. Penny
Thank you very much. We go to the first slide there, Chris. And we see 3 things here. Drilling, fracturing, acidizing. Fracturing, we've been talking about because that was the big application where we can clean up the fracture and increase the relative perm to hydrocarbon. And so that's been the primary focus of what you've heard so far. So are there other applications out there? That's what we're going to talk about today. Yes, there are. So first one is drilling. While you're drilling the well, you can actually minimize the drilling damage with water-based fluids by using CnF. And so we have some case studies on that and we're back to basics of promoting that. So that's one additional application.
The second one is down the bottom there is acidizing. So we can increase acidizing penetration efficiency cleanup productivity. And where do you acidize? It's Carbonates and gold mines, this is over half of the formations in the world, okay? So the other application is the improved oil recovery or enhanced oil recovery. So in this area, when we started this business with CnF, we were remediating, removing paraffin, asphaltenes, emulsions, water blocks and so forth when the wall wasn't performing. So right away, we noticed we can improve productivity of the well by treating it with CnF.
As we moved on further in IOR, injection well or producing -- producer cleanup. So we can put our CnF in the acids or in delayed acids, and I'll talk a little bit about that. In IOR, you typically take water as the first program, you do a waterflood. And you notice right away, the water's breaking through, so you need conformance control. So if you're doing a CO2 flood, you have the same problem. And so we have CO2 diversion, we'll talk about. And then we've also added polymer injection as an additional form of conformance, which allows us to get this water flood or this CO2 flood back, making a front to displace oil.
We also have some applications where we can add CnF and oxidizers together to enhance the polymer flood cleanup. Once we have a polymer flood, as this water's starts coming up, you have a mixture of polymer, water and oil. And so you have to get those apart. Well, the oxidizer doesn't work real well but if you put the CnF with it, it enhances that process and was able to do it much more efficiently.
So let's go to acids. So its been applying acids worldwide and it has increased effectiveness. If you apply 0.2% to as much as 5% in some of these Middle East jobs then we observed more effective flowback, longer effective frac length after frac acidizing and improved oil and gas production. So it's the same thing we saw in fracturing. Now we're just putting acid in there to etch the pattern on the walls for the connectivity. And many times, we'll do fracture oxidizing and proppant at the same time. So this is another application and we're looking at several applications of this, as well as just normal fracturing, for example, in Saudi Arabia, which we talked to many of you about last night. As far as applying acid, we're also looking in -- at Mexico, which has a lot of carbonates and dolomites, and were applying it along with CnF, that's something that we're working on at the moment.
Next slide. So when we go to real high temperature wells, now we have a problem as HCl reacts too quickly. So here, at the bottom here, we show a core and we're pulling HCl through there. And this is a CAT scan showing the dissolution of that core. So this is really, we call it phase dissolution. So if you were throwing down a wellbore, it's just dissolving the carbonate around the wellbore. Well, the ideal things you want is what we call a wormhole. So, let's say this is a wellbore here, you want this to create a wormhole and then penetrate the reservoir, maybe going out 3 to 6 feet, to get away from the wellbore, where you now -- you have a connected channel with the reservoir. So this what you want to do.
As you go to higher temperatures, the HCl reacts too quickly. So now we have, in this case where I'm showing you, 2,000-foot horizontal lateral and if you put 15% HCl in there, and it's showing you at what rate have to pump to penetrate so far. And we don't even get out there to 300 feet pumping 10 barrels a minute. So we have a process that we call chelating. So we have a chelant and we put CnF and chelant together, at about 10%, and it will penetrate, as you can see, much further. So 3 or 4 times further than the HCl by itself. So this is what we've been internally working on. So this process is what we're investigating in our Texas A&M where Professor Nasr-El-Din, who came from Saudi Aramco, where they have plenty of carbonates to acidize. He has all the acid equipment there so we have a -- as you saw in the press release, a JV with them to look at these various operations. One of them is acidizing just like this. So we're going to apply this process in the Middle East, so we're looking at cleaning up the injector wells over there, for example. So they have injector wells that are pumping maybe 1 million gallons a day. Say, they have breakthrough so this is where performance comes in with Jay Portwood here with EOGA. And then we have acidizing to improve the injectivity.
Okay. Next slide. So another way to get the acid out there is to delay it from [indiscernible]. So we have our conventional CnF, like our MA-844 or our second generation, as we call it, StimOil. We put it together with a chelant, which has an ester in it, which is slowly releases. So we have this in our original patent. So we envisioned that some of these things could happen and now we're here, where we're going to apply them. So on this slide we're going to show the red dots. So the chelant will react at all temperatures but if you delay it, here at 25 degrees C, nothing happens. And by the time it hits 50 degrees C, then it starts to release with time. So this allows you to get even further down the wellbore. So we're taking the CnF together with that and slowing it down, is what we're doing.
Next slide. Let's talk about conformance a little bit in the EOR process. So our first entrée here with CnF was in CO2 flood. So CO2 comes in and it's supposedly displacing the oil banks and taking it toward the producer. Well, eventually, it will break through because there's a difference in mobility and so you have this channel where all the CO2 is going through straight to the producer. So in the WAG process, this is water-alternating-gas, we can add a customized polymer that we have made with CnF and we put this in here in the water phase, follow it with CO2, it blocks off that channel and now the CO2 behind it produces a miscible zone again and the oil bank produces towards the wellbore producing more oil. So this is the process that we're using. And we can also do this just with CnF by itself. So this is a case where you have a break through going straight through. By putting the CnF in there, we're able to alter the whole path where the CO2 is going. We've created a greater miscible zone and we're seeing oil come out the other side. Next slide.
We're showing an example on one of the field studies that we did using our StimOil IOR FD-1 foam diversion one for conformance. So this well was producing, at this rate, and it was declining. We injected and then, we went to see a couple of months later and you start seeing the oil come out. And as a result of that, we find we had an additional 14,000 barrels produced that wouldn't have been produced without the diversion. So this is the process that we're trying to implement in several places with some of the major players that are pumping CO2.
So the other thing we have was conformance. Conformance control is a cross-linked polymer business. And we have now conformance studies and services with EOGA. So there's other forms, it's Preformed Polymer gels, PPG, and there's what we call Colloidal Dispersion Gels. So there's 3 types that are applied. And what happens here, you have a high perm zone, we call it thieves zone, that's taking all the water and you can inject either at the injector or the producer of both, and you shut the zone down, now the water will go through the oil zone where the residual oil might be and displace it. So Jay has been very successful at doing this around the country and for that matter, around the world. So we're pleased to have him as a part of our team to enhance oil recovery. Well, that's all I have right now. Who's the next, Chris?
John W. Chisholm
Now, I have the pleasure of introducing Jim Crafton. We know Jim for so long, and I can't care or really tell you how long, but it's over 25 years. He's the former head of Colorado School of Mines Petroleum Engineering Department. He's the independent source that we went to about 3.5 years ago to -- at that time, we didn't know if he was going to validate or disprove what we saw was the value of CnF. We told Jim, we said, "Here's the data, you look at it, you pull it apart and put it back together." And part of the deal is if it's bad results, we need to know that. Well, the good news is, the data then was good and the data now is even better.
Part of Jim's credentials, this fall, the highest honor you can get out of the Society of Petroleum Engineers was to be a Distinguished Lecturer, joined by 6 of those folks that are selected every year. To my knowledge, this will be the second time in his career and maybe more than that, but at least 2 times, he's been selected as a distinguished lecturer for the Society of Petroleum Engineers. So this fall, he'll be charging that around the world. And part of the topic he'll be talking about is improving the efficacy of fracture stimulations with nanotechnology.
So Jim has had a chance to look at hundreds of wells, thousands of fracture stimulators and has had that complete third-party impartial look as to why folks should economically figure out the rationale for employing Complex nano-Fluid. Jim is notorious for telling bad jokes. So we've asked Jim to keep it to a strict 15-minute timeline. But all ex-college professors, they're part-time comedians. But then Jim will walk you through just a great bit of information. I think when you leave here, you'll really have a better appreciation of nano-fluids.
Thanks, John. I've had a privilege of looking at this and I've got to say, one of the bravest things as a corporate strategy that I've ever encountered was John's willingness to let a third party investigate with the possibility that the results would be bad. Because there was every chance that, that would have been my conclusion. It has raised a rather interesting scenario of events because as I've dug further and further into this and as he said, "I've got a fairly sizable data set now." I keep discovering that this stuff persistently works in a beneficial way. And in fact, I've become so confident about it that when I have discovered situations where it didn't work beneficially, I have become convinced and have been in several cases, able to go back to the client, the producer, and engage them in a discussion about what went wrong. And in many cases, that has been very beneficial to all parties because we discovered that there are other issues at the table about oil management and what have you. So I want to dig into that a little bit as we go forward here.
My business relationship with CESI Flotek is, as I have said, a third party. My task is to try as best I can to remain independent. So one of the things that I do as part of my analysis process, I do not know what was done to the wells when I evaluate them. I think that's a very important piece of the discussion because obviously, it would be a legitimate concern on your part. Well perhaps, you knew that this well had CnF in it and that well did not and therefore, he biased his analysis. Well, that's the point of this conversation, is I'll attempt, as best I can, to not have that information before me when I do the evaluation. Only after the evaluation is done, do I then segregate the data set and look at the behavior of the 2 groups. In fact, in many cases, it's more than 2 groups. I'll be looking at issues about the way the well was completed, the number of shut-ins, a variety of different parameters.
Well, that's the point of this conversation, is I attempt as best I can to not have that information before me when I do the evaluation. Only after the evaluation is done do I then segregate the data sets and look at the behavior of the 2 groups. And in fact, in many cases, it's more than 2 groups. I've be looking at issues about the way the well is completed, the number of shut-ins, a variety of different parameters. And we want to dig into that a little bit here. I don't want to spend too much time with it, but just to kind of get you to understand.
My client is actually the producer. They provide me with some production histories, they provide me with the well descriptions, they provide me with the frac reading reports and that sort of information. The agreement that I have with them is to not provide that data any further than my desk. It dies right there. CESI / Flotek is not welcome to see that. I am not at liberty to share with you where these wells are, what the well names are, where the locations
are. I can tell you, "Well, it was the Bakken." I am not at liberty to tell you whether that well was in North Dakota or Montana or Saskatchewan. That's simply a means by which the producer feels comfortable with providing with -- or providing to me data, which otherwise would be considered confidential because, obviously, it represents a major competitive advantage for them. So that becomes the basis of this study.
I am permitted -- and that's part of the conditions of our agreement, I'm permitted to share the results of the analysis with CESI, with them and with you, with the public in general, but not any of the original raw data. That's kind of our agreement. Clearly, with those ideas in mind and with that disclaimer in mind, what I'm going to look at here is to try to engage -- next slide please.
Because I'm talking to a group of fully financial experts and I'm just a stinking, little, old petroleum engineer, that's my history, I thought I'd better put a disclaimer of some sort so you'd feel at home with it. But I really want to say to you and what that's intended to do -- ideas trying to bring forward, I've looked at almost 1,000 wells, of which, 500-some are usable data sets. The unusable data sets were incomplete data sets, too short a history, a variety of different issues. But approximately half of that original 1,000 wells are usable data sets. What I've done is distill that data set into a hypothetical type well, and that's what we're going to look at today.
For example, this data set has -- the value I'm using for reservoir quality is 6 microdarcys. That's a little high for a typical shale well matrix, but that is the logarithmic average of the data set of this 500 wells that I've analyzed. So I'm certainly hypothesizing that this is descriptive of something. For example, on average, the logarithmic average of time for the installation of artificial lift is 120 days. I've got wells in this data set that didn't have artificial lift installed on them at all, so they fell out of the analysis. But my analysis is using that average to look at the impact of artificial lift. Shut-ins, on average, logarithmic average of this population of 500 wells, the average number of shut-ins before the installation of artificial lift was 4, 4 shut-ins. Well, to keep my life simple, I simply said, "Okay, I'm going to have those wells, have 4 shut-ins 22 days apart." Well, as you can imagine, that's not the real world at all. But that's really the purpose of these comments right here is to bring your attention to the fact, I'm not attempting to represent to you in any way that this hypothetical well is a real well, but I believe that it is realistic because I have based it on the actual data that I've acquired. All right, please?
15 different studies, 7 different basins, 11 different companies, 518 interpreted well data sets and literally thousands of fracs, something over 4,000 that I've had the opportunity to look at. And as you might surmise, that's coming up on several gigabytes of data sets. But it's a compelling data set. I really felt like, in our original conversations with Flotek / CESI, it was imperative that I have a data set robust enough that there was no basis for argument that I was looking at 1 well and drawing conclusions. Please?
Several of you recognize several faces here. When I made this presentation last year, I was able to give you some of these numbers, so I thought I better give them to you again. But the news is even better. Roughly 2/3 uplift in oil equivalent recovery, gas plus oil, which we adjusted for the 518 wells, 76% higher at 30-day liquid hydrocarbon recovery, which is really in a day -- in our current oil price scenario, that is compelling home run. The fracture lengths have actually improved compared to wells that do not have CnF in them. This last result is basically a 2.3-fold uplift in potential gross incremental value when compared to a non-CnF-bearing well, realizing that I modeled the wells based on the population of these 518. Please?
Traditionally, I would look at the cumulative production corrected for the reservoir quality, fluid properties, et cetera, and I would investigate this question about fracture lengths and corrected, again, for the various factors that affect that. But today, what I really want to focus on is this gross incremental value idea because that has been -- there's so much pressure on these producing companies to cut costs, manage the cost, manage the cost. And they just -- the engineers are beat up on about this issue. So one of the questions becomes one of not just cost, but is there value to be added by having somewhat higher cost. Please?
I want to take on a rather different perspective. When CESI originally offered this product, their understanding of the universe and their goal was that this was a means by which to improve the frac job itself. That its efficacy might last for hours or days. And what I've come to see in looking at these data sets, and a statistically significant size of data set, obviously, yes, it does exactly what they said it would do. They were correct. However, they really missed what I've now come to believe, and this is really the point of this conversation today, there are several other pieces to the story. The fact that we're seeing production in these horizontal wells, just simply for safety reasons, if no other, there's a significant period of time from the end of the frac job to the time the well's put on production, the delay. Many operators refer that as the soaking time or the [indiscernible] task to marinate or whatever. But I want to investigate whether CnF has a role to play in that phenomenon, that operational issue. The next piece is the effective shut-ins. Do shut-ins have any impact, beneficial or adverse, on the performance of the wells? And then because these artificial -- these wells have to have artificial lift installed on them, that's the fourth phase of the life of the wells. So I want to try to investigate that piece. Please?
This graph begins to engage this idea of trying to wrestle with the concept of the incremental value question. The orange or red line, as your eyes may see it, is the well modeled as if it had no CnF in it. The properties that I've seen from this population of wells are described by that orange line. The green line represents the behavior of the well when it has the CnF in it, or the old MA-844W. So those 2 basically result in that 20-year forecast, with about 100,000 barrels difference between the 2, beneficial to the effect of the CnF. Based on the economics that I did, 20-year forecast, $4 gas, $90 oil, and of one of the things that I did that's probably kind of foreign to your view of the world, my clients, when they're making decisions about high-risk projects internally, very commonly use very high discount rates on their cash flow stream. So I use 35%, which means that I have extremely front end of this cash flow stream. I have basically taken into account any conceivable risk by raising that discount rate so high. Well, I figured that, that was a fair way to treat this because by that means, if this actually does add value, then certainly, I've looked at the way it's treating it at the front end. So that's the difference that I've seen there. Next, please?
That same line, the difference between the red and the green line on the previous graph, just translates itself to this difference graph, which you see here. I'm looking at 1/19 -- 1/20 of the data set. The other 19 years are out into the next room. But I wanted to really focus on this first year to kind of get your attention to the events that occur and how they occur. So that represents what ultimately will be that $2 million, and we've already gotten the majority of it in that first year. Next, please?
Because these wells, horizontal shale wells, on average, logarithmic average, are shut in for 24 days prior to being put on production, you see the shift of the yellow line from the orange line. The difference is that wells that do not have CnF in them suffer roughly 30% loss in productivity in that 24 days. Wells that have CnF in them do not suffer. They basically do not have any harm that was observable in those data sets. So without -- the difference is that uplift is the consequence of the loss in the non-CnF wells. Please?
The greenish line here is now the next step up, is the consequence of the 4 shut-ins. The 4 shut-ins, wells that do not have CnF in them, on average, suffered 37% loss in connectivity between the reservoir and the wellbore, 37% loss in fracture lengths for each shut-in. Wells that have CnF in them are harmed also, but only to the -- the average of this population was only 8% loss. So basically, that's the green line. The uplift, as a consequence of having CnF in the well versus not having it was the difference basically between the baseline here and the green lines. Then comes time to install the artificial lift. Please?
The light green line, now realizing that this cash flow stream is discounted at 35%, makes the gap very small. If it was undiscounted, that gap would almost be $2 million in its own right. But with the discounting of it, because it had so front end of it, and this is now 140 days out into the life of the well, the gap looks smaller. But once again, wells that do not have CnF in them suffer a 27% loss in connectivity in effective fracture length compared to the CnF wells. So the CnF wells, again, experience an additional uplift. And that's why I raised the thesis, that's the reason I put that same statement at the first, this is an insurance policy. I buy an insurance policy to protect my life and my car against things that I know might happen, but they're only might happens. I know these wells are going to have artificial lift installed on them. I know these wells are going to experience shut-ins. I know these wells are going to have to be delayed before they're put on production. And I would propose to you the thesis that I have just discovered, no surprise, I've just discovered an insurance policy. We'll flip at the end of this graph from the other side, please?
This is the full 20 years. And at that kind of discount rate, it's no surprise that the lines go basically flat. To put some numbers on it, the initial frac difference was that $2.4 million we looked at, initial frac was 24 days, brings us to $3.1 million difference in value. And the shut-ins, we get to $5.1 million. Shut-ins plus the installation of artificial lift, and we're $5.6 million difference, discounted at 35%. Please?
Looking at the end of the graph and just to provide you with some basis for understanding of how robust the data set is, the 518 wells were the basis for the understanding about the difference from the apparent fracture lengths initially. 320 wells were in the data set to investigate that delay time. 277 wells were evaluated to look at the effect of the shut-ins. And 103 wells had artificial lift installed on them, to be the basis for that $5.6 million. Please?
Because I'm an engineer, I had to show you an engineering graph. I couldn't just do everything in terms of dollars. I had to put on my engineer hat. So this is my engineering graph. The story here, the 500 number on the far left, on your left, that represents 100 mesh proppant, the very low-grade proppant that many operators have found to be useful because it's so inexpensive. CnF is beneficial when used with 100 mesh proppant. But the real story is when we come over here to burst a pop or cargo pop the 3,000 millidarcy-feet high conductivity proppants, that's a 2.6 value uplift in using for 30 days observed production. This is not a forecast, this is the observed production on 353 wells. 353 wells. If you're going to use the good proppant, then use CnF or serve the other way and far more important to the Flotek business model, use CnF and use a good proppant to go with it. Please?
My observations are: 66% higher 30-day oil recovery based on observed data, that's not a forecast; 3/4 [ph] higher liquid hydrocarbon recovery, and again, that's based on observed data, not a forecast; 46% or essentially 50% better fractures; 40% less damage occurs when you're using CnF based on 320 wells' performance; 300% better results when you look at the effect of shut-ins, 277 wells; and 250% better performance where artificial lift is installed. All of that adds up to an incremental value, a potential incremental value of $5.6 million discounted at 35%.
How long did I take, Chris?
You owe me about $300.
Oh, geez. We had a bet running, and I just lost.
But you're fine.
So let's end [indiscernible]. And for the benefit of the schedule and I think it makes sense because the data is interesting, compelling and also pretty in-depth, if you don't mind, and I don't think [indiscernible] but you're used to it, why don't we take a few minutes for questions on the technical nature of the data, if there are any, with our press [ph].
Which particular shale formation does it work the best in? Do you have data on that?
I do, and I guess I will frustrate you considerably. I have not seen a fundamental difference in its performance. The thing that's kind of neat about it, and I think this is something that's pretty compelling, Marcellus -- the original core of the Marcellus was considered to be an absolutely dry gas, no-liquid hydrogen carbon production area. Several operators are now operating in the Marcellus and discovering that by using CnF, they've been able to convert what they thought was dry gas and do fairly substantial liquid additional recovery. And you go then to something like the Eagle Ford or the Barnett, for example, which are considered oily shales, and it's just as effective. And the problem, just to be a little bit of a subjective question, because with the value of gas compared to oil, what you're going to perceive there would be more beneficial in your oil plays. My perception here is driven by the productivity of the well trying to stay, in a sense, trying to stay away from the economics question, even though everything we talked about was economics-based. The real question is, and kind of to respond to you, as far as the benefit is concerned, obviously, it's going to be the best in the oil play because oil has a disproportionate value right now. But in terms of uplift productivity, I don't see a fundamental difference. It is beneficial essentially regardless of GOR.
You said you got the potential [indiscernible] life of the well. But what is the offsetting cost to get that [indiscernible] IRR number on that [indiscernible]?
Well, may I run and hide from you on that question, because I don't honestly know. That is a question for Kevin or John or somebody.
Marc Kevin Fisher
First of all, CnF is [indiscernible]. Well, I think a good number of [indiscernible] is probably worth $100,000 to $300,000 per well on average [indiscernible].
The response, for those of you on the conference call, the question was, what is the incremental value and what's the cost of the CnF. And Kevin Fisher just responded that it was something in the order of $100,000 to $300,000. Is that fair, Kev? Good question, but I'm on the engineering side. I just put gross dollars on here to kind of scale the problem for you.
Can you clarify [indiscernible]?
Well, yes, going back up 2 slides. There, that's good enough. Basically, the original work that I have focused on was strictly driven by looking at the initial fracture. What happens, does this stuff improve the behavior of that initial fractures? Comment has been made several times about load water recovery, those kind of questions. And I was able and still am able to affirm that that's a valid claim. But what I had, because I had such a robust data set and especially in the Marcellus, because of a major operational issue up there about the ability to connect the resources, and the same issue exists in the Bakken, takeaway capacity just is virtually nonexistent. So these operators were shutting the wells in for extended periods of time. And because I had the data set, I thought, I may as well see if there's signal in here. Does the CnF impact those events? And so, essentially, what I did was I extended my horizon of investigation, not just from the first 30 days. This data set that goes out here to the artificial lift phase actually extends almost 3 years out in many of the wells. The average -- the log average time is 120 days after first production. But the actual block of history goes out several years literally. So the big change was the investigation of these other 3 events in a much longer time horizon, and that's one of the surprises that I think it's kind of challenged them to revisit what in the world does my physics worth [ph] the physical chemistry that allows this stuff to persist. All of these datasets were wells in which the CnF was placed in the frac job and yet, there's obvious impact, literally, months later. And that has kind of confounded the guys about, what did we do.
[indiscernible] do you think that the [indiscernible]?
Well, can we go to that other -- I don't have that slide in here. Never mind, sorry.
Is it another [indiscernible]?
Yes, I think it is. Maybe. The one that shows the population of wells after first shut-ins. [indiscernible]. So to give you a bit of -- this is a huge issue in the Marcellus, in particular. But it's a huge issue in all these operations simply because if you got a well on a pad and you're getting ready to drill or frac the immediate next well, you're going to have to shut the first well in simply as a safety issue, let alone the any kind of other causes. So...
Absolutely does. Well, to be really careful, no, it does not. It depends on your business model. And one of my clients actually changed their business model after they investigated this very phenomenon, realizing that they were better off to not put any well on production until after they had finished everything and put all of the work, all of the frac jobs at the very end; drill all the wells for all the pipes and you roll that, then do the stimulations at the very end. So the rear end model of that. And what they discovered -- that was -- it's the next one? One more, I think. Oh, no, go back. Sorry. This looks like an easy question. What I saw, and this was driven by some questions that arose in the Marcellus, the impact of shut-ins when there is no CnF in the well, shut-ins are categorically damaging. Out of the population of wells, that roughly 154 wells, the first -- after the first shut in, 7 wells experienced benefit out of that 154 wells. 5 wells were as if they had never been fractured at all. The damage arising from the first shut-in was so bad that the well was dead. By contrast, of the 123 wells that had CnF in them, of 123 wells, over half of the data set had improvement or no change, which was a huge difference. Because here, the vast majority of the non-CnF wells were severely harmed. The CnF-bearing wells actually experienced benefits as a consequence of the shut-in. That's really what -- this difference between these -- the 2 bars here, this is the damage of the average that actually you can see that the one is actually slightly approved. So the CnF has the effect. Now that's not to say. And you'll see that after you beat up on the thing sufficiently and finally, it turns okay. You kicked me so hard that I am going to get hurt, and it does happen. I mean, as a categorical statement, shut-ins are harmful. But we have to do it. I mean it's -- you don't want to go see what happens in open-heart surgery for the same reason. Some things just have to happen. But using CnF is a mitigator against the damage.
[indiscernible] sometimes, there's no value-added and sometimes it's extremely [indiscernible]?
I apologize, I didn't include that graph here.
Well, let me address it this way. As far as the standard deviation, the statistical question is concerned, the good news is, when CnF is used and properly used, and that's a very important caveat, obviously, I found operators that would actually pump it in one stage assuming that, that was beneficial to all 55 stages. Hello? There's a very critical issue that arises in the concentration of the CnF that's used. And what I've seen, that once you go below about 1.5 gallons per thousand gallons of stimulation fluid, once you go below that concentration, it is still beneficial, but the standard deviation of the data set is huge. So the critical idea is, that once you're about 1.5 gallons per thousand in the stimulation fluids, the standard deviation is still quite large, but it is not negative ever in the data sets that I've seen. And by contrast, and this I think is perhaps the most important point, when I look at it for the non-CnF wells, the standard deviation of the data set is much bigger and does go negative. Yes, sir?
What I -- yes and no. The no part is, I do not have a very robust data set above 5 gpt. So I really can't say, with any kind of authority, what happens above that concentration. Once you go above about 2.5 gallons per thousand, the benefit, I think, probably becomes questionable. There's -- it looks like to me there's a sweet spot between about 2.5 and 1.5.
Just a follow-up on that [indiscernible] Eagle Ford, one of our clients is [indiscernible] 25% uplift in recovery. Now they're running several wells [indiscernible]?
Great. The question was whether is there a sweet spot. And John made the point that one of the clients of CESI is looking at going through a range of concentrations of use of CnF starting at 1.5 going to 2 gallons per thousand, 2.5, and investigating where that sweet spot might be in terms of its value add. Is that a fair statement, John?
John S. Reiland
[indiscernible] include the Wolfcamp formation and [indiscernible]?
It is, yes. Wolfcamp and Eagle Ford are part of this data set.
Do the non-CnF wells include a surfactant for...
Yes. The non-CnF wells include a whole variety. I mean, I chose not to try to break and stratify the data set by taking into account all the different non-emulsifiers and what have you. Three of the studies have looked specifically at competitive other surfactant systems, or surfactant systems as compared to the CnF-based systems. And I can tell you with absolute confidence that the actual CnF-based fluids when compared to the other surfactant systems, when I knew specifically and was specifically looking at them, there's no comparison. I guess that's the safest way to say it. The performance is -- well, the data set is big enough, but the probability is in the order of 1 part in 10,000 that the 2 behaviors are the same.
[indiscernible] the question is, I'm not sure if the [indiscernible] proppant of the 500-plus percent of extracted [indiscernible] in the company that at 3,000 [ph] would benefit [indiscernible]?
Exactly. Yes, it is cost. The question is, why -- on this graph, looking at the behavior of the CnFs versus the proppants, why would one use a low-quality proppant, the 500 millidarcy-feet versus the real [ph] high-quality? Probably the average right now of most operators is in the order of that 1,500 value, the third point over from the left. The use -- very typically, they're using something in the order of 30/50, or 40/70 proppants, which are very inexpensive, readily available, and in my opinion, of very marginal quality. And one of the big issues -- this graph, you'll notice, it looks only at the first 30 days of observed production. One of the things that happens with those lower-quality proppants is 60, 90, 120 days out, they begin to fail very rapidly and especially because of the shut-ins. But the real issue is the fact that if you're using a really low-quality proppant -- well, I should be really careful. If you're using a high-mesh proppant, 100 mesh, for example, I can show you wells that have incredibly good IPs. The problem is, if your business model says I want to drill the well and permit, then you may choose to do that. That maybe a sufficient business model for your practice. If you're going to drill a well and intend to look forward to a long-term productivity, you're going to want to go to the other end of the graph. And that really becomes the core issue is how well does the CnF and the proppant work together. And the thesis -- I think this data begins to engage that idea, that the high-quality proppant, in the presence of a CnF, protects the well over a much longer span of time. Does that refers to what you're asking?
Yes, that's fine. indiscernible] increase with a higher-volume proppant or #1 and #2, more competitive [indiscernible]
Let me recite the question. The question Was, what is the -- is there any correlation between the work that CESI is doing and some of the other single pad or cargo prop [ph]? And so Kevin's going to respond to that in a second. Can I wrestle with that first? What -- Chris said I could do it. Scary thought. One of the major issues here, obviously, is the cost question. And that plays a huge role in it because you're looking at probably price difference of 4 or fivefold from the propane left side to the right side of that graph in terms of proppant price. I've had the privilege of doing some work with the premium proppant vendors, and their data supports exactly this observation, that the use of the high-quality proppant has compelling and long-term impact on it. So Kevin?
Kevin, can you talk really loud?
Well, come up here.
Yes. Well, I wondered -- Jim, I thought -- I want to ask here from a technical perspective why CnF high-quality proppant [indiscernible]. Is it because it's going to increase fracture length, it's built on longer or what [indiscernible] explanation to that [indiscernible] increase in the higher proppant?
I believe at several things. One of the things that people really misunderstand, in my opinion, shales flow. They literally -- I can show you some wells in Western Colorado that I drilled that I successfully pulled shale into the wellbore. It's actually a very plastic material under the right pressure conditions. And so what will happen, and there's some data now that's developed at University of Oklahoma, where they're showing that after a period of 180 days, the embedment of the proppant is 3 to 5 sand grains deep. The proppant literally pushes, extrudes or intrudes into the matrix that severely. So the idea as, that if I'm looking at 100 mesh, which basically has no structural integrity at all, it's going to essentially disappear into the matrix. Whereas, if I'm looking at a high-quality proppant, with much larger sizes, it simply does not have the propensity to embed and disappear into the formation. Another factor is diagenesis. One of the things we have never looked at and understood is the fact that these proppants chemically change over time and they become very weak and basically dissolve. The ceramics don't do that. So that's another piece to it. And then the third piece is simply the stress issue, the fact that the proppants are prone to crushing. So there are 3 different pieces that play a role in moving across that graph. The point is really well taken. And I'd like Kevin to wrestle with that idea, but I think there's some huge upside. Because this phenomenon, there's additional uplift, are those 3 issues, and I think there's a fourth one that really goes right to the heart of what CnF is about, and that is the interfacial tension that exists in that fracture. Glenn has done some really cool work in looking at the impact of capillary pressure in the fractures and how reducing the interfacial tension of the fluids in the fracture can significantly benefit the ability to remove the fluids from it.
I haven't [indiscernible] about the joint venture marketing. So the short answer is no, we've done no joint venture marketing, but this [indiscernible]. It came out with that graph [indiscernible] high-quality proppant. [indiscernible] both the uplift on the short term but also the durability of [indiscernible] or absorbable [indiscernible] for the long haul. There's some old data, and Glenn might have it, but [indiscernible] find it. But [indiscernible] portion there is [indiscernible] chart of the things that [indiscernible] hit some in the fracture. And the pretty thing is you get [indiscernible] connectivity. So and that's also a [indiscernible] somewhere between normal [indiscernible] connectivity in that [indiscernible] is always saying, you can't have too much connectivity. [indiscernible] both amplify that connectivity and extend the durability.
Maybe for Kevin. When you present those data [indiscernible], what were you expecting?
Marc Kevin Fisher
Well, the first factor, they're both expensive. Ceramic proppant expensive. CnF is more expensive. So now we've added that, but [indiscernible] the benefits of applying both of those. But one of the things, and we've been [indiscernible] lately within Flotek is that ceramic benefit is over a long term, first 3, even 9 days of [indiscernible] that durability and connectivity that goes with ceramic outperform after CnF [indiscernible]. You're going to get more of the load water back. you're going to get down from [indiscernible] back in the same sooner than if you run a conventional surfactant and you're starting to see that [indiscernible]. So it really is [indiscernible]. You just have to make your decision [indiscernible] Do I want to invest in both ceramics and CnF or one or the other? [indiscernible] together they both add [indiscernible] But either one [indiscernible]. You can only choose one or the other.
And to carry that piece a little further. Two issues there. One is not all ceramics are created equal. And that's a really important issue because a lot of operators perceive, I bought ceramic, and therefore, I've got the same performance. I've got a data set that shows that one vendor's -- one, not U.S.-based vendor's proppant, ceramic proppant actually performs no better than brand 20 40. And so you've got to be sure that you're buying the right surfactant -- the right ceramic and the right surfactant, in the first place. The other piece of the puzzle is that a lot of operators have started not using the total job of ceramic so, they're popping 20 40 wide or something like as the first part and tailing in with ceramic. And I've seen that to be a very effective alternative to minimize the cost there.
[indiscernible] have you found the total length of [indiscernible]?
Well, some of you remember that the theme last year was Save the Planet, and that really was the thesis, that we do not have to have as big a job if we want the same performance. If performances -- if a specific performance is our goal, then when we look at these performance numbers that you've seen shown here, we have the alternative of choosing some other strategies, not the least of which is a smaller frac job. I had the privilege of doing some work for the American Association of Petroleum Geologists, and the question was, can you tell us where the point of diminishing returns is for lateral length and number stages? And I can tell you that I created a fairly adverse audience because what I saw was beyond about 7,000 feet, and it was not an function of the basin. It was a function of the performance the wells. Beyond about 7,000 feet of lateral, it was as if there were no additional lateral out there. Beyond 7 stages, it was as if there were no stages added. I have a record right now the longest well I have looked at was 23,000 feet, and 55 stage -- and 75 stages. And it was as if it had 5 stages. Yes, so you might -- well, and the bad news is, my client invited me to come and make the report and then invited me not to come back.
[indiscernible] background like you have internal studies going in Flotek? [indiscernible] do you get done and what?
Well, I chew -- here is what the academic ending comes out. I have become convinced that because of the cost pressure this brought against the engineering staff, just like it is the drilling staff and the completion staff, the engineers do not usually have the time to do a really thorough in-depth study. And I've got several situations where -- in fact, for CESI, where I've gone back to the client and shown them my results, and just as you say, gotten tremendous amount of pushback. And my challenge to them is, show me your work and I will show you exactly in detail what I've done. And very quickly, we'll go through the entire study, item by item. And invariably, they will have simply looked at the cumulative production and then the cum prod of these population wells show the CnF didn't work. When I dig into it, I discover that the wells that look like they were underperformers might actually be in depletion already, they're interfered by offset wells, or the reservoir quality was poor or the frac jobs were much smaller. That's a very common phenomenon. In one of these data sets, I actually found out that the wells that have CnF in them, the frac jobs were literally 1/10 of the frac jobs of the so-called good wells. And when you take into account treatment size, all of a sudden, you're confronted with the fact that the CnF wells actually outperform the others. Unfortunately, so frequent that these operators simply don't have the time to do a really thorough in-depth study.
Have you ever [indiscernible] pad drilling [indiscernible] rather than [indiscernible]?
No. The question is, whether our pad drilling has caused things to look different. I apologize I didn't hand the technical on you, but one of the things that is true in these shale plays, and Kevin certainly began that conversation with the talk and his pictures about -- that George [ph] had put together. Fractures jobs are the story. The natural fracture systems are crucial to these shale plays. And what you'll see, I've got data sets where we had 16 wells on the pad, and if you look at them without knowledge that they were on the same pads, you wouldn't even think they were in the same basin. Because the natural fractures in them are different. Now the new thing about it is, the matrix firms [ph] may be quite similar but these natural fracture systems will be radically different. And as a consequence of that, their performance is quite different.
One more, and then we'll take a break.
Does that [ph] point about the [indiscernible] fractures [indiscernible] natural [indiscernible] fracture areas? Is it, it doesn't do much? Is that [indiscernible]?
I've got several clients I'd like to send to you before I go. The question was whether or not the natural fractures might be seismic and help us predict to understand that. And the answer is yes, absolutely right. We have developed the P&S wave analysis in classic seismic that provides an excellent. And I've got several clients that have actually done studies on that and showed that very clearly, they can anticipate what that setting is going to look like. Now unfortunately, then your business strategy comes in conflict with science, because one of the huge drivers of these long laterals is not an engineering question; it's an acreage question. So there's some politics and other issues at the table that we have to respond to.
Jim, thank you.
Thank you very much.
We have the [indiscernible], so maybe you just want to check them. And we have a 15-minute break scheduled here. We will reconvene -- we'll reconvene at 9:45 a.m. and talk about financials and the rest of the business. And we're going to take some questions from the group.
For those of you the on webcast, we will reconvene in 15 minutes at 9:45 Eastern Time. Thank you.
All right, we'll get started here again. Just a housekeeping item. When we're done here, we have a couple more presentations, and then we'll have a discussion. You'll have time to go back to your rooms, if you're going on the bus to Winter Haven. And the bus -- the bus will pick us up at the front lobby, is that right? Okay. So we'll meet -- we'll synchronize our watches as to what time we're going away, and we won't leave anybody. But when we leave here, if your bags are still in your room, you have time to go back to your room if you're going straight to the airport. If you're staying here, obviously, we'll bring you here after -- back here after Winter Haven as well.
So with that, I'd like to introduce Rich Walton. Rich joined us earlier this year on a full-time basis as our Chief Financial Officer. He stepped in on an interim basis earlier than that. And honestly, most people don't know this, but Rich, after a storied and colorful career in the public accounting world, if anybody could have a colorful career in the public accounting world, he came to Flotek, when John and I came in 2009, as a consultant to help with reporting and trying to put the ship on the right path. And so he has some history with the company from the outside, and now on the inside, and we're delighted to have him. He brings some gray hair and a lot of experience in public accounting for public companies. And so, Rich is going to walk through the performance we talked about or we filed on Friday as well as information on segment reporting and some other tidbits. And then he'll be available after that for discussion as we wrap up. So Rich, thank you.
H. Richard Walton
Thank you, Chris. I'm glad to see that you've all come back after the break to hear some of the exciting things that are happening in finance and accounting. I do want to talk about this segment that we have at Florida Chemical. I know that many of you follow how -- follow us by our segments and how each of our segments are doing.
If you look at Flotek historically, our Chemical Technologies segment has accounted for over 50% of our business, our Down-hole Technologies business has accounted for over a 1/3 of our business, and Artificial Lift Technologies have been less than 10% of our business.
When we made the acquisition or merger with Florida Chemical, we had more business and actually other activities within Florida Chemical that we needed to reassess the segments that we used to report to the public. And internally, we spent a long time looking at and evaluating the various alternatives.
You may recall, when we introduced Josh to you during our last quarter's earnings call, he revealed that at Florida Chemical, they really look at their business in 3 areas. They had the petroleum business that accounted for about 40% of their revenues. They had a flavors and fragrances area that covered -- that accounted for about 28% of Florida Chemical's business. And then the specialty chemicals business accounted for approximately 32% of their business.
And when they looked at their business and who they served, they really looked at their customers. It turns out that their customers are primarily in 1 of those 3 areas. And so you can take the sales to specific customers and get those percentages.
So we spent time looking at how we would manage the business. Really, when you look at segments, that's really a key in the reporting. It's how the company manages a business. Florida Chemical, because they were a private company, never had segment reporting to disclose. So they never broke their business out for any public scrutiny. But even internally, they looked at the business often as a -- what I would call a single group.
We ultimately decided, and the conclusion internally was that Florida Chemical's business would be segregated into 2 reporting units. One would be petroleum, their energy business, which would be combined with Flotek's historic Chemical Technologies segment. So part of their business, that 40% of their business, is going into our Chemicals Technology segment.
The remaining business is going into a new segment, which we refer to as NECT, and that's Non-Energy Chemistry Technologies. I'm going to show you a chart. This gives you a general idea, but you will see that the blue or the green, Chemical Technologies, still accounts for over 55% or over 50% of our business. The Down-hole Technologies segment accounts for approximately 30%. So it's dropped a little bit below the historic 33% or over 33%.
And then you'll see the new segment, which in this chart is NECT, it's the blue, the light blue. And that is, what, historically within Florida Chemical has been their flavors and fragrance business and their specialty chemicals business. And we're calling that Non-Energy Chemistry Technologies.
And you will see that on our quarterly filing. We will be, as we've announced, we will be releasing our quarterly numbers next week from Wednesday, that's on August 7. So you will see in that filing, all of our information will be presented in 4 segments. So it will be something new.
As I mentioned, we are taking the petroleum business from Florida Chemical and reporting it in our Chemical segment. And any -- because Florida Chemical sold products to Flotek, that business and that particular -- those transactions will be eliminated in our consolidation. So it's not taking 40% of their annual revenues and adding it to our historic presentation.
Next, I'd like to just address a little bit of how Flotek handled the allocation of the purchase price. It was -- this was a very significant process that I'm very pleased to and really proud that we were able to complete that process as of now. We have completed it. Our advisors have looked at it. Our auditors have looked at it. And they agree with the way that this process was done.
Management, of course, is responsible for the purchase price allocation. We, in fact, hired a third-party appraisal firm to assist us in that process, and we had them look at the business of Florida Chemical, really in those 2 reporting units that I've already mentioned to you. So we looked at there and considered the risks in each of those pieces of -- in each of the reporting areas. And they weren't different. And I'll just tell you that the energy business is a little more risky than the non-energy business of Florida Chemical.
Conclusions reached. When we looked at the fair value of the property plant and equipment, the current fair value of that asset is very -- was very similar to the net book value of that asset. There was about $0.5 million increase to the $20 million that was the net book value of those plant equipment at the date of acquisition. We also looked at the intangible assets, and we spent a lot of time identifying the intangible assets that we acquired. A lot of those assets, of course, were not on Florida Chemical's historically financial statements because they weren't something that they purchased. It's things that they developed over time that had a value that would not be recognized in their historical financial statements.
So we looked at the trade names, we looked at the proprietary technology, and we looked at the customer relationships. And we found a significant value in those, and I'll address each of those briefly. But in total, those 3 intangible assets, the first 3 you see listed there, accounted for just over $55 million of value.
Trade names, example, the name Florida Chemical Company. This is a well-known company, the largest processor of citrus oils in the world. They've been in existence for 70 years.
Customer relationships. They have customers in the flavors and fragrances line of business that have been customers of Florida Chemical for over 30 years. Not quite as long in the energy business, but they have customers that they've been serving for between 15 and 20 years. Flotek has been a customer of Florida Chemical for over 15 years. So those were some significant intangible assets that were acquired.
Goodwill, that's the -- is the consideration paid less the value of scientific tangible and identifiable intangible assets. The goodwill number came out to be $14 million. And when you look at our reporting, you'll see that we've increased that to $40 million. And the reason is, which you see on the last line here, we identified the deferred tax liability. And that's related to the difference between the book basis of our asset and the underlying tax basis. So in the future, there will be some maybe amortization of or there could be some write-off of -- if possible that when you do your annual evaluation, you might reduce the value of some of these assets. And if that were done, it has an impact on deferred taxes. So you'll see an increase in the deferred tax liability, and that bumps up the amount of goodwill that you'll see reported. And I would tell you that in our filing on Friday, and it is included in your packet, if you look at the footnotes to the pro forma financial statements in the very back of that filing, you will see the total purchase price. That is what we paid in cash, plus the value of the stock that we issued, plus the debt. And that was not a lot of debt, but all of the debt of Florida Chemical that was repaid at the date of acquisition. Comparing that and it will show you -- you'll see the specific amount for each of these intangible assets. And that was done based on the 2 reporting units, and then added together for the totals that you will see.
In the filing that we had priority in our 8-K filing, there are the historical financial statements of Florida Chemical. So that's a good source for you if you want to see how has Florida Chemical done historically. You will see the audited financial statements for 2012 and 2011. Total assets at the end of 2012 were approximately $42 million, and their revenues for 2012 were approximately $102 million. I think I said thousand, it's million in each case. $42 million assets, $102 million revenue. Their net income was $8.7 million. But I do want to alert you or make you aware that, that number does not include income taxes. So when you look at their historical numbers, because they are treated as an S corporation, there's no income tax expense recorded. So that $8.7 million is before income taxes.
You'll also see in the filing that we filed Friday the historical quarterly financial statements of Florida Chemical. These, of course, are unaudited but it will show the first 3 months of 2013 and compare those to the first 3 months of 2012. You will see, if you'll look up those, that the assets increased about $9 million, and most of that was in the area of inventory. This is a time of year when Florida Chemical is building their inventory. The supplies are there, and it's just historically the way the business has worked and will continue to work.
Revenues in the quarter were -- the first quarter of 2013 were $22 million. Net income, and this is again before tax, is shown as $3 million.
Also in the filing, there are pro forma combined financial statements. And these attempt to combine the financial results of Flotek with the financial results of Florida Chemical. And this is -- it's really is, a what if. The accounts will tell you that it it's not a -- it isn't what would've happened if the company's had combined in an earlier point in time, even though that's what it's shown. But that's not what the results necessarily would have been. It's also not a prediction of what might happen once we have occurred, and we look forward to the next reporting period.
I think one thing in these pro forma financial statements, one thing that happens is, the historical assets that are being depreciated, or some of our intangible assets, the ones that have a finite life, they're being amortized beginning right at the date of acquisition over their estimated useful lives.
The historical assets that are being depreciated or some of our intangible assets that the ones that have a finite life, they're being amortized beginning right at the date of acquisition over their estimated useful lives.
Those amounts are added in because they were being added into the numbers that you get to see on August 7.
And all the historical depreciation and so forth is removed. So there are certain of those things that you will see. The pro forma financial statements also show you the estimated income tax that would've been occurred if Florida Chemical had been a taxpayer. And we assess that amount, just for your information, at 38.7%. That was 35% for federal. We look at the individual states where Florida Chemical, its Wyoming's state income tax returns and try to determine what an ongoing rate might be or might have been.
And we do look at costs that are -- they have to be directly attributable, factually supportable and expected to continue to be included in the pro forma. So what it does not include is integration costs, acquisition costs. There are some of those. Those are not reflected in the statements that you would look at. Also, any synergies or benefits that we might get from working together in the future within our operations, they are excluded as well.
So my point is it's not a complete picture. But if you do look at the 2 income statements, that for the year ended December 30, '12 and also for the first quarter of 2013, if you looked at the EPS numbers for both basic and diluted earnings per share, you will see that there's either a $0.01 or a $0.02 accretive benefit relating to this acquisition, at least in the pro forma numbers. That's not a prediction of what we might see in the actuals, but it is one way to look at what this might mean to Florida -- to what Florida Chemical might mean to Flotek in its ongoing financial statements.
I wanted to speak to you just a minute about accounting integration. This is something that we have spent a lot of time looking at and working with. We have spent a lot of time working with Tom Hodge, who is the CFO at Florida Chemical. He is an individual that you will get to meet this afternoon on the tour. I did let him up today. He's still cranking out the numbers down there. And he is supported by a good team down there as well. And they have been handling a lot of requests. They had the -- the previous auditor's been in there, looking at the numbers that are included in this Form 8-K. They had to reissue their audited financial statements as of Friday. So he's handled their questions. We are a lender. The new financing arrangement that we've disclosed to you, those folks have been down there and knocking on his door asking questions. We, at Flotek, and used in a corporate event asking questions of accounting and others at Florida Chemical. So he's been addressing a lot.
I wanted to mention when you look at our financial statements for quarter 2, when you look at those in 2 weeks, it's important to realize that the balance sheet will include Florida Chemical at the end of June 30, at the end of the quarter. They will also include the activity and the operations of Florida Chemical since the date of acquisition, which was May 10. So basically, you've got 2 months of Florida Chemical activity and 3 months of the classic Flotek activity that you will see in the numbers.
So we'll go back one -- just a second. I wanted to just talk a little bit about the migration of the process because that is ongoing. An example of something that's already been accomplished and has been accomplished successfully is bringing Florida Chemical under Flotek's payroll system. The benefits -- payroll and benefits and now have been fully converted. And the folks that were involved in with that have spent a lot of time, but it was successfully done.
And so let's see the next slide. Yes, I want to just go back and mention one -- just mention, when we're looking at the accounting integration of Florida Chemical, we are going to bring them under our new ERP System, which is JD Edwards. That -- yes, we're looking at when that will occur. There've been several trips already to Florida by folks in Flotek's IT department. And they are -- they have assessed the situation. They are working with them to bring them under the JDE system. I'm not certain exactly when that flipover will occur, when they will go live on our system, but it will be most likely no later than January 1 of 2014. It could be earlier, but I would say I anticipate it will not be later than January 1.
A couple of things -- a couple -- I have a couple of comments I want to make about the JDE ERP System. Those of you who are following us know that we went live on July 1 of 2012. So we've been under this system for just over 1 year. There were some hiccups when we started it. And in fact, we've identified and report in our quarterly filings and our last year end filing, and this was actually beginning with the third quarter of 2012, right after we implemented and went live, we identified material weaknesses that occurred really due to this conversion to the new accounting and reporting information system.
Those hiccups related to IT, and some of that was segregation of duties. That all had to be -- some things that didn't work the way we had anticipated or things that we realized we could get that we had failed to program into what we had already had when we flipped the switch. There are also some accounting issues that arose, and these were primarily related to the monthly close process. When we had a new system, we found out that all of our account reconciliations that we had diligently done for a period of time had to be modified. We also found that the monthly trend in margin analysis reports that we historically had generated and relied on needed to be changed, needed to be modified and changed. There was a lot of training involved. We have spent really the last 9 months addressing the issues. And I will tell you that management believes that we have successfully remediated these issues as of June 30.
We have as our auditing firm to look over to our shoulder, and to evaluate and test the testing that we perform to imitate whether, in fact, these deficiencies are remediated.
So you will be reading about that in our Form 10-Q filing in 2 weeks.
I want to just mention some of the benefits. I think that the new system has really permitted the company to enhance its controls. These would be primarily the controls over financial reporting. I think it's provided -- I know it's provided additional information for operations. It's for the executives and management in each of our units, but it's also for the sales force. It's also for the people in the manufacturing plants, the plant operators. They're getting additional information out of our ERP System that helps them run the business better.
Of course, one of the main reasons we implemented this system was for the enhancement of financial reporting. That was really a plus. And I want to give you an example that I learned of 2 weeks ago. Flotek in our chemicals technology segment, we maintained a perpetual inventory. We do a physical inventory twice a year. And that's just to make sure that our perpetual systems working in any differences are investigated, reviewed and cleaned up.
The process in the past has taken, in Oklahoma I'm talking now looking, doing physical inventories there. It's taken us about 2.5 days. We just completed the semi-annual physical inventory, and it took us between -- it took approximately 7 hours. Why? Information we're getting out of our new ERP System, it also is -- the information that's going in is real time. So we don't have paperwork that's not entered that's causing discrepancies that have to be investigated. I think a real plus was that this -- in this physical inventory, we actually shut down operations. And so that made the process of doing the count, checking it, doing -- go back and doing recounts if we have to and performing the whole reconciliation process. It was done well, activity. And while shipments and so forth were not moving, it makes it a lot easier to do. When you're doing an inventory over 2.5 days, it's very disruptive. It causes a lot of things, extra stuff you have to watch. So that's an example. There are many of those. And I think we'll see many more as we get further into the JDE System.
So I encourage you to look to watch. So that's an example. There are many of those. And I think we'll see many more as we get further into the JDE system.
So I encourage you to look for our filing in 2 weeks. Thank you.
Rich, thank you. Steve?
Steven A. Reeves
Hello, everybody, and welcome today. A couple of things we're going to talk about on here. Obviously, we're down here to see Florida Chemicals, to see the new addition and for everybody to see that. We decided also to throw a quick slide up here because 35 -- it is important, all the Florida Chemical that's coming in, the chemistry technologies that we have to tie together of them. We also are just going to give a couple of highlights of 35% to 40% of our other business on the Artificial Lift technologies and the Drilling technologies. The first thing I was going to lead off with, I was going to talk about our capital expenditures and where we're spending the money.
Tie this to cash outlay, in 2013, we have a capital expenditure budget of $19.3 million. First half of the year, we spent $10.1 million of that $19.3 million. That was cash out the door coming in. We expended and I'll show some pictures in just a second. But the chemical facility up at Marlow, we've gone out. And about 50% of that $10.1 million has been spent on that chemicals facility to increase -- we probably have 2.5x the capability that we had in 2011 right now up there.
I'll show a picture as to what that ties into. On the Drilling technology facility, some of you come up last year at our presentation and we went by and we saw in Chickasha, Oklahoma, we have a facility there. It's just about to fall down on us. Out of our 30-plus facilities, it's really a pitiful place to be. I can't state this enough. So we took in upon and we are not big brick-and-mortar folks. But this had to be redone. One of the things that we have up there is in Oklahoma, we have a good motor business, we have a good actuated tool business. All of that stuff has to be shipped back from the field that comes back to the facility and Chickasha. And it ships back to Houston, Texas, to our Cavo facility to be rebuilt, shipped back up again, then set out to locations. Obviously, huge inefficiencies. So by building this building that we're building in a -- we'll put it right next to our Teledrift building in Moore, Oklahoma. And we're about to finish it up. We should be moving in, in about a week. And we'll have some pictures, but just the logistics part of it. And the utilization parts are going to add a lot to us.
In the Artificial Lift section, we completed our Dickinson, North Dakota facility. I'll talk a little bit more about Artificial Lift and why we would go there and look at another piece on that. The stimulators, I'll talk about those a little bit. They were a nice piece of our budget up there. And I'll talk about them more in our down-hole tool section in just a second. And then our corporate software, like Rich said, we spent a pretty nice piece of money this year, but it was for some reporting software, for some, like he said, the segregation of duties, some things we had to. This is paying off big time on the reports that we get back out of it.
In the second half of the year, on our estimated capital expenditures, probably about $7 million is going out, maybe a little bit more depending on whether we get into anything, how much more we get on to some -- a little bit more construction. We will finish up our chemical facility at Marlow. We'll have the lab facility we talked about. We'll add another 50 stimulators to the pack. Up in Waller right outside of Houston, from FC-PRO that we got from Florida Chemical, we'll have a tank expansion project up there, both taken in -- addition. We're adding that on because the clear people that ask what keeps you awake up at about Marlow, 2 things keep you awake: everyone knows at Oklahoma has a tornado, okay. These are kind of devastating. We have a picture that I won't show the tornado coming close to our Marlow plant. Now we're kind of sent back. And it's never hit and some got hit once. Fire shuts you down. So what we've looked at in these 2 situations is where do we have redundancy of backup? Waller, we can do most everything. If everything's going right today, we are actually blending product today in Waller, Texas. That would be for a catastrophic failure in Marlow, Oklahoma. So we'll have backup and be able to keep going. So we're adding a little tank expansion down at FC-PRO, completing a chemical facility, like I said. We're going to have some expansion of our F&F a year Winter Haven. That will be built then. We have some potential EOR expansion and then some of the basic, just you replace some rolling stock and so on. So we look to spend about $7 million in the second half of the year, be about $17 million, $18 million about time we're through for the year about what we expected to do, okay? As we look at this, this is the chemical technologies. As you can see over here, the one in the upper right, that's the back of the chemical facility we have right now.
All of the blending is done in this. The bulk tank farm, which is these other 3 pictures out here, are about 200 yards out behind it, which was in an open field. And the piping goes, which is not quite completed, from the facility up on the top back to the bulk tanks back there. So we can actually do the blending inside. We have tripled our blending capability on the inside, take it out and set it in the bulk tanks and it will come out. These are scales that they pull into out here. And it's all fully automated and run from the outside. There's an outside building. So we have added in, I guess, 8 to 10 extra large tanks with room to modularly add more on. So right now, we have the capability to do. And we don't have this fired up and running, it's not quite there. But by expanding the piece in the upper right and the blending facilities in there, we can actually put out 2x, 3x more blender products with no overtime.
We're still working at less cost than it cost us to operate a year ago in there to put out more products. So it was all for efficiencies.
The next one, this is the thing -- this is next to our Teledrift facility down at Moore. This is our Drilling technology's expansion from the outside. You can see we're just almost through with it. This is the inside of 1 well. These are jib cranes over here you where you will replace -- where you will work on drilling motors to wash right back in the back. On the other side of it, we've taken our Teledrift facility, our operations out of there, and it is going to go in this side over here. So we will be able to do all of our motor work, everything that we've shipped back to Cavo and Houston and do it out of here.
And we'll be in that, like I say, hopefully in a week to 2 weeks.
This is our facility up in North Dakota. This has to do with our Artificial Lift technologies expansion. We built this and got it finished in the first part of this year because -- I'll show you some units in Artificial Lift. We see just a tremendous market up there. And even though it's a tiny piece of business, I'll do more explanation. There's 2.5 acres also with this that we can build more on. We are going up maybe this week by the end of the week and looking at putting a Drilling Products camp up there on this facility and sharing it. And then there's room to put some chemical up there also to have a place out.
So this is a nice piece of our business. It will grow. We'll grow into this thing pretty rapidly.
A key point for our Artificial Lift, and we know that's a small piece of business right now, but a key point on it is we're getting in to these, they're called a sheer stroke intelligent lift systems. And if you will see that -- you see the old traditional pump deck here on the right-hand side, okay. Then you look over here at the other, all of this section going from here to here is the distance you can pull the sucker rod right straight up and right straight down, okay? We have a manufacturer in Canada, Tendra [ph], who were looking at -- we're going to partner up. They're going to build them if this all works the way I think it will. We're going to ramp them and be the sales and leg of this and start putting them up. What this gives us in Artificial Lift is I could -- this gives us the capabilities now to go to location, replace the pump jet with this unit here. All of the advantages are in your book there you can read off. You get twice the lift on it. So it cuts down the wire on the sucker rods and so on. But we can replace with a smaller footprint, replace with this right here. To give you an idea on this, 170 rigs running in the Bakken, every another drill 1 in a quarter, 1.5 oils a month. See it like a 250 rigs a month just in the Bakken alone. Every one of them has to have one of these put on it, okay? This is exactly the same as the Weatherford Rotaflex coming out only less descriptive. The smaller of these units can be put on for about $125,000, just the unit itself. They go up to the bigger units, up to about $350,000. Then you have the set of rods that go down the hole all the way down. So you can sell those. At the bottom of it can be a pump. You can sell the Petrovalve so you can put a full system up now with this. So obviously, we've taken this own to see. I told Joe, who is our Manager, "If you can get 3 of them rigs out in the next couple of months, we'll really get into negotiations of how we're going to set this up." Joe managed to get 4 of them on wells. So it looks like we're going to be talking and going out. But this will be -- it won't be the type margins. Obviously, it's commodity product. But this can really push Artificial Lift. Once you start getting everything else, then you can get the oilfield pump installation down-hole. Those have margins on them. Those are very good margins down there.
So we're hoping that this right here opens us up a tremendous amount in Artificial Lift. I'm excited about it and Artificial Lift had a tough time exciting me. The first time I went out and sell one of these, I got pumped up. I can see where this could work. So and obviously, our guy is doing selling 4 of them in the first month of pushing it. They know how to make it work.
Okay? This right here, a little stimulator. This is in our Drilling technology. This is -- I'm beginning to wonder if this is just my dream, okay? When you work in the Drilling industry out there and the wells have gone horizontal, as you're drilling those wells, and you think about this beyond and you think about the pipe flowing out there through 7,000, 8,000, 9,000 feet, there's a friction in a drag that is just tough to overcome. There's a chutney [ph] up there, a little witty [ph] chutney called NOV. And they have this tube called an agitator. And it really works great on giving an axial movement of that pipe and keeping it moving at all times. So it overcomes friction and drag. They bought this man [ph]gauge a few years ago. And I guarantee you, they did not realize at that point that although horizontal drilling was going to come around and be what it is now. This is a nice piece of change, give you an economics on it. You rent it for about $3,500 a day. You rent it for the drilling of the horizontal well up through there. You start putting that together and you realized that up in North Dakota once again, let's go with the 175 rigs. There's probably 120 agitators in the whole drilling. So this has the same type of margins on it that our Teledrift does. And Teledrift margins beat any margins that is standing in our releases.
What was that again?
Steven A. Reeves
Our Teledrift MWD tool that we run, that's about 1/3 of our down-hole tool. The margins on Teledrift performance are better than anything you see on the gross margins in our reports down here.
Teledrift is a heck of a business for us on this. This will have those kind of margins, okay? So they will match it. So when we start talking about this could be $1 million a month for us adding up, this is a nice piece of change. Obviously, at that, one of the things that NOV had, they had a tremendous patent. And we had to come from another way. John and I have discussed this a little bit, and it's kind of like NOV now has -- they've got -- they're the hearts. They had the hearts. Well, I want to be the A-list. But there's about 10 companies out there that want to be the A-list also. And there's other ones of these outfit word, but they don't have the axial movement that you'd have to have. We've run several of these successful as -- and we've had several failures getting it done and the beta type testing. Right now, we have just put our last version out. We have 10 of the 5-inch and 10 of the 6.5s. We have 4 of them on location to be run of the 6-inch and 4 of the 5-inch. And we'll have those run in the next 2 weeks. But my top of these I have that these are going to work, I already have 25 of the 6-inch -- 6.5 inches built and I have 50 of the 5 inches built. And it's just changing small parts inside. You're down to just really engineering some things.
And we're close to getting this in. So I do like the last line down there that Chris puts up. He always adds one in, better to stimulate than agitate. I believe that. So we will be giving for the first time a true option to the people out there. Think about just the Bakken and all horizontal, this is good, okay. But in the Bakken, with 175 rigs going all horizontal, probably 140 of these, 130 of these in the whole, you can do the math, led over to any of the other horizontal type applications you'll see where it's at. Another application for this, my poor head of engineering is about to pull his hair out if he had any. Think about the completion side of the business. As soon as we get through getting this thing to run in the open-hole, you hook this because we're not. Coil-tubing is going out and drilling through all of these bridge plug settings. There's all that force that's going to overcome pushing itself out. One of these down at the end of it, keeping that agitation going. NOV does it. So now my engineer's going to build me a 2 and 3/4 inch of one of these. He doesn't just know it yet. But there is just a tremendous market for these every place.
But there is just a tremendous market for these everyplace. But we're pretty excited about that. Another thing in our drilling technology side is we were talking -- I was just talking about Teledrift, and it ties into our opportunities international. International opportunities take a while. You have to be patient, you got to do things right, and it still takes a while. For example, in Teledrift, we have an agent over there who got us a contract with Aramco. The way that the contracts work is, first, you get a short-term contract. This allows you to come out and test your equipment. You're running it for almost nothing to prove to them that you have a viable piece. So you work through a short-term contract, you get all the tests, you get approved in every field that everything you've got is working, it meets their needs, takes a while because there are several different fields. After you get through with that, you go into what's called a mid-form contract. Your mid-form contract has a set amount of money against it over an amount of time. When we work from the short-form contract to the mid-form contract, we went from running in the $20,000 to $40,000 a month to the $150,000 to $200,000 a month. But the mid-form contract is very limited. You run out of money on it and you're done. We ran out of money a month ago on the mid-form.
Now remember, we've been working on the long-form contract 4 years. The long-form contract will have the same type of -- once you get off of that is it's a $7.5 million contract, and it's up to you to go sell it, kind of like a government contract. How quick can you capture $7.5 million? If it takes you 3 years, shame on you, you didn't maximize your contract. You have to have your salesman out there. If you can capture that $7.5 million in a year, in 10 months, the beauty of the long-form contract is it rolls over. They reload it again. So that's why you try so hard to get a long-form contract. Right now, we have the paperwork between us and Aramco going back and forth. It did get caught up in our wonderful mail system, a certified mail in New York for 4 days last week. But we've signed the paperwork. It's there. We will be on the long-form contract. Point of all this is it is going to be a very lucrative piece of business, i's going to be very good for us, 4 years of constant effort to get a long-form contract done it. So we know that's an extra long time, but it does take patience when you're doing these. The payoff will be great, though, because the margins are exceptional on this work once we get it going.
That's pretty much it.
John W. Chisholm
Well, I think you can see now why when my friend did strong calls and says, "John, how are you doing?" I tell him, "It's great." Because having a chance to work with a team that you saw present today, how can it be anything but great? And I hope they were able to convey to you why Flotek has such a special opportunity. And it's really humbling to have had a chance that when we got into this in 2009, Flotek had a ratio that I don't think anybody has ever survived from, and that was a debt-to-revenue ratio of 1:1. And the guy that's been -- just pushing the slides over here, they're really orchestrated, the capital rewiring of Flotek, is our good man Chris over here, that if he hadn't had the energy and the grip and the creativeness, none of this would be possible.
So now we look back and look forward. Our second quarter, and this is in the press release, pretty much consolidated $93 million: Chemical Technologies, you can read the numbers, $47.5 million; Drilling, $29 million; Artificial Lift, approximately $3.4 million; net, $12.5 million. If you look at Florida, Flotek classic, it's greater than $79 million, which will put us either at the first or second best quarter in the history of Flotek classic since we've been around.
If you look at the gross margins, consolidated, that's 40%; chemicals, 43%. I don't know anyone on the planet that in 2009 would think we'd be standing here and talking about Drilling Technologies gross margin of 41%. A tremendous accolade to the leadership of that whole Drilling Technologies group to get us to an over 40% gross margin. Artificial Lift, 25%; Non-Energy Chemical Technologies, 29%. Let me hold here for just one second and try to explain to you a part of the real dynamic to Florida Chemical and Flotek.
The more d-limonene we can sell, whether it's in CnF, whether it's in xylene replacement, whether it's taken BTEX out it, we'll move our limonene from non-energy up into the higher-margin area for the consolidated enterprise. And so this number here is going to be impacted over time to where there'll be less and less d-limonene in that segment at the lower, more generic margin and more driving up there, which will, overall, just give us the opportunity for even a greater consolidated gross margin.
So what are the drivers in the second half? We want to continue to improve the marketing penetration of core CnF products. I'm sure some of you, when you saw the technical part of this between Kevin, Dr. Penny and Jim Crafton, you're thinking why in the world, if you're running an oil and gas company, would you not run CnF? The numbers are that compelling. Well, the story gets better every day, every week, every month in terms of the validation of why you would want to do that.
And at the end of August in Houston, there's going to be an Eagle Ford Completion Symposium. 7 or 8 operators are going to be speaking there. There will be an operator, for the first time, that talks about publicly their economic evaluation as to how they justify Complex Nano-Fluid with respect to expected ultimate recovery. Never before publicized in a public forum. That's one more step in validating what you had a chance to see here today.
Execute on new environmental opportunities such as the BTEX replacement, pretty obvious. Florida chemical integration, with the opportunity for expanded margins, we're just getting started there. Rich talked about migrating the payroll, okay, so it's important there that we gets paid on time and all of that, pulled that off. But in terms of integrating the supply chain between Marlow, Waller, Winter Haven, we really believe there's a 200-plus-basis-point opportunity there to streamline that whole inventory effort, the purchasing effort and all that, and we're focused on that.
Here, international opportunities, you've heard us talk about that and, of course, the press release early this morning about how we can layer on to our EOR effort that we're just committed to, both here in the United States and also internationally.
We're going to give those conclusions. I wanted to spend just a second maybe letting you to even understand a little bit more about the philosophy of Flotek. And the human behaviors have a term that they talk about quick gratification horizon. And what that means is a lot of us, both personally and professionally, have been pushed into this desire to have, if not immediate, short gratification horizon. You want to have the next promotion as soon as you can, the next raise as soon as you can. And even some of the investments, the horizon is next week, next month, next quarter. And the internal philosophy of Flotek is almost opposite of that. When we got involved in 2009, it was $600,000 cash in a bank. We were spending $2 million a year in research. If we wanted short gratification horizon, I would've driven up to the win-wins, put a padlock on the door and shut it down. Instead, we doubled the expenditure in research and development. And that enabled CnF to migrate from -- as Kevin mentioned, from just a dry gas additive over into oily type applications.
In early portions of our board meetings in '09 and '10, we had a director say, "Regarding this drilling motor business, just put a rope around it and sell it." Didn't do it. That's part of the 41% gross margin. We had another director say, "this Permian Basin thing, put a rope around that and sell that." For heaven's sake, Teledrift is on 135 rigs in the Permian Basin. I was talking to one of our individual shareholders, George Mark [ph], last night, when you focus on immediate gratification horizon, then you're giving up the opportunity for patience. Invariably, with patience gives you the chance for success. And Flotek is not so much of those important about tomorrow, the next week, the next month, the next quarter. It's really about how we're putting this together for 6 months from now, a year from now. And I think the history shows, with the graphs we showed all through this, just exactly how that internal philosophy of Flotek works.
So conclusions, you can read them, we talked about them. We really are about making a difference with our customers. We've got an acute focus on the return for our stakeholders in the way we distribute this capital, in the way we look after that balance sheet, in the way we look after our stock and the fact that our most -- last 2 acquisitions, the folks has taken 50% of -- up to 50% of the value of their companies, and Flotek stock, we think, goes a long way to our shareholders of sending a message that those people are willing to say they're going to grow with Flotek.
And so it's been a special time here this morning for -- to share the Flotek story. We've got time for a conversation and discussion. And on the bus, certainly, we can extend it there up to Winter Haven, lunch out there and all that. But what do we got, 15, 20 minutes if there's questions, Chris, or...?
Absolutely. Why don't all of the Flotek guys [indiscernible] in the table [indiscernible] to deal with Flotek questions [indiscernible]. It's hard to do it. [indiscernible]. So I know we've kind of hit you with a firehose of information, but fire away. Sure.
You talk a lot to about all the opportunities, and that's wonderful. Like your core business has a great threat [ph] [indiscernible] Now the question is can you talk about [indiscernible]?
John W. Chisholm
Well, I think I'd probably -- the biggest threat for us is folks that try to imitate what we do. A lot of times, when you imitate you don't have to have near the research commitment, near the infrastructure sales commitment. And in terms of primarily the chemical side of things, I hope you can see a lot of imitation of the drilling technology side of things. But I'd say that's the biggest threat is folks who try to have some type of generic knock off out there to try to catch in on the way of the Complex Nano-Fluid. We've got patents and all that, and that's one of the main reasons why we made the acquisition with the Florida Chemicals, because that d-limonene is the key kernel to the whole complex nano-fluid trough out there.
Can you talk about the migration of usage [ph] from dry gas to oily type [indiscernible] oil liquids [indiscernible] there's a lot of moving pieces happening right now?
John W. Chisholm
Sure. The question for the folks on the call is what's the migration of kind of the usage of the technicals -- of the chemicals. Kevin, Glenn, either one of you guys fire away with the answer on that.
Marc Kevin Fisher
For the dry gas activity that they have [indiscernible] Marcellus [indiscernible] activity that really [indiscernible] dry gas the [indiscernible] today, that the story of the [indiscernible] Permian Basin out there that's sort of a story [indiscernible]. I gave you the number [indiscernible].
John W. Chisholm
Sure, go ahead.
John W. Chisholm
Well, that's a tough one. I know you'd like that quantified. Josh, if you can throw out a couple of numbers in terms of what that BTEX kind of market looks like.
Yes, the BTEX market for oil and gas and [indiscernible] product, if you look across North America, we equate that to [indiscernible] it's quite a volume. If you look at BTEX, those are [indiscernible] solvent, that is the complex [indiscernible] you get outside the U.S. [indiscernible]. And on the applications [indiscernible] very [indiscernible] with that range. And we're not going to talk about [indiscernible] talk revenue numbers out, but certainly, [indiscernible].
[indiscernible] introduce [indiscernible] technology [indiscernible] or programs [indiscernible] or objectives would be as much as possible and virtually all of those. And as you get engineers to work into those technologies such as [indiscernible], so the technologies [ph] side of the business, it's just in relation to the [indiscernible] with all the presentation, so we could process [indiscernible] high and low [ph] [indiscernible]?
Sure, George. [indiscernible] or Rich, the [indiscernible] on R&D in the 8-Ka shows no R&D for [indiscernible] as far as the completed and historically, [indiscernible] and it is [indiscernible] given our [indiscernible] and [indiscernible] although [indiscernible] activity and scale [indiscernible] for chemical [indiscernible] go.
It's probably going at [indiscernible] 35.5%, 35% [indiscernible] of 35 to [indiscernible] take [indiscernible] around 300 [ph] [indiscernible] during [indiscernible]. But when we get there, it's about [indiscernible].
John W. Chisholm
We certainly hope it does.
John W. Chisholm
Sure, go ahead.
What's the current market penetration of CnF? [indiscernible] if you expect to get to the 3 years?
John W. Chisholm
Yes, sure. A fair question. We've tried to be as transparent as we can on that publicly. I think the penetration right now is about 7% of wells that have an application for CnF. And we've said publicly that in 2015, we expect to triple that. That's based on, in a large part, it used to be just Kevin and my experience of -- in the industry selling value-added, but we've been able to add some really significant sales talent most recently, Tom [ph] and William [ph], that's had a history of selling value-added. So when you look at that, CnF right now, on a yearly basis, is about $100 million. We expect to have it at about $300 million in 2.5 years. That's certainly our expectation we've thrown out there. That's about as much guidance as we've given at any one time. Sure, Brian.
The 3 major total market for CnF is about 35% wells drilled [indiscernible]
John W. Chisholm
Well, look, yes, the way we'd look at that, and it's pretty high and not the most scientific, but it's based on history of value-added things, like micro seismic, like ceramic, like tracers, that they penetrate about 30% of available wells. And so we've set that as a target for us that we should be able to do that. Our mission is to do it faster than anyone else, and part of that is because we've got the scar tissue. Kevin, thus, you need to speak to it as well about how you try to ramp that up, so go ahead.
Marc Kevin Fisher
[indiscernible] the coke [ph] market availability is 100%, so 1/5 [ph] there is value-added. And today, there are even some [indiscernible] there are not a lot, but there are some [indiscernible] the fact that [indiscernible] so our job is to [indiscernible] from all the [indiscernible] the products [indiscernible] from the total market out there [indiscernible] hasn't gotten there yet, but it's [indiscernible]
John W. Chisholm
[indiscernible] what their history was part of the business [indiscernible]
John W. Chisholm
Well, yes, every time we've got into those individual conversations, it seems to kind of circle around us. But I think we can fairly honestly tell you the most enthusiastic user of CnF is Noble Energy in the D-J Basin. And they run about 100% of their wells. And part of that is they were in the life cycle of products, where there's an iPhone or whether it's CnF, they're the early adopters. And the guy who runs that show was an early adopter, who said, "I really don't care what the CEO has to say. I believe that we're going to spend money to make money." And so they've consistently run that on 100% of their stimulation. Yes, sure.
John W. Chisholm
Well, yes, sure. So actually, in analyzing that, what you call bottleneck, but really, it becomes a show [ph] factor as to what is limiting more widespread adaptation, right? So for the first 3 or 4 years of this product's life in the previous administration, and they were thinking that it was all good at that time, it was to sell to the supply chain, selling to the technology side of the big service companies, the distributors. It's been our experience in the previous life that [indiscernible] didn't wake up this morning saying, "how can I help book that?" And neither did [indiscernible]. So you have to get the right skill set at the beginning to carry the message into the team level, at least the asset manager level of these operators, to be able to make them comfortable that, in fact, that Jim Crafton said it's going to cost more to make more. And so the business model, although folks have questioned it recently, over the last 60 years, is that we sell by the legal aid and [indiscernible] into the distributing companies, Halliburton, Schlumberger, Baker and the other 40 folks. They market up, and the end-user pays for it. So we are clearly on a mission to make that end user, and Kevin can talk about that better than I can, aware of why they need but go ahead [ph].
Marc Kevin Fisher
Indiscernible] earlier today what comment at the time [indiscernible] to further [indiscernible] distributors and focus [indiscernible]. And if you look back at [indiscernible] ability to [indiscernible] store the 80% of [indiscernible] 50% [ph] of the products [indiscernible] and sell more in [indiscernible] today rather than [indiscernible] companies, but there are assets that are being managed [indiscernible] and maintain their relationship with certain companies. And I don't want to [indiscernible] as well. I just don't understand -- they can't explain [indiscernible] and our job is to go create that visibility and create that desire, adding [indiscernible].
John W. Chisholm
[indiscernible] representative [indiscernible] in this business?
John W. Chisholm
Actually, it will be presented in September. And currently, CnF is being -- 2.0 is being contained to one particular service company and probably assume it's going to be one of the larger ones on different applications in different basins. And at this point, that's what we can say about it, except they are requesting repeated used on different wells, which we felt would be the case. But we're still in that stage of understanding that.
Volume [indiscernible] might go through [indiscernible]
John W. Chisholm
Under the right conditions that we think cascade into our shareholder base, that is our preferences. We think we can control the value of that if it's on an exclusive, at least, geographic basis. But that is still to be determined business model. Anything else? Again, Paulo.
A lot of questions had been asked. [indiscernible], and you guys get a lot of support [indiscernible] and it comes down to [indiscernible]
John W. Chisholm
Kevin could talk to that for a little second. But we -- on chemical, it's very hard to say that they get $30 or $50 per gallon benefit for someone to pump essentially what delivered to the location, but Kevin can talk to that.
Marc Kevin Fisher
Well, the service companies, of course, has the [indiscernible] was one of those [ph]. And the proper place for a frac job of oil [indiscernible] he referred to [indiscernible] certain companies are starting to [indiscernible] they choose how to outpace that. Once there is something might actually build most of their revenue on the frac-ing point [indiscernible], what they do is they invested [indiscernible] to [indiscernible] that extra recovering might really move it up from a [indiscernible] and kind of commoditize their own pumping business to prove that our job is similar as the [indiscernible] with the price of that. But if [indiscernible] the companies choose [ph] the latter and their [indiscernible] do the pumping further despite [indiscernible] and that maybe there is money on the mark-up of [indiscernible] product, it makes it harder to sell value-added chemicals because of that embargo. But at the end of the day, the total process [indiscernible] similar amounts for everybody, no matter how [indiscernible]. As John said, the real challenge and the real opportunity is to [indiscernible] company and [indiscernible] certain companies [indiscernible] would frac-up out there and demand or request that they pump [indiscernible].
John W. Chisholm
How will the studies [indiscernible]?
John W. Chisholm
If you didn't hear that, there's 3 studies that are kind of backlog based on the other requirements Jim has. So it'll be a continuing effort to give the most updated information to the client base in industry out there.
[indiscernible] could you expect [indiscernible] probably [indiscernible] some [indiscernible]
John W. Chisholm
[indiscernible] competition [indiscernible] on the environmental concerns and kind of the timeline of using the environmental permitting [indiscernible]. What do you have to think about in terms of timeline [indiscernible] improvement [indiscernible]
John W. Chisholm
So the timeline [indiscernible] combination, they did all the way, on one end, arising to the part of the experiment, where you [indiscernible] Important side, [indiscernible] probably where there's unbelievable -- that probably where this is driving legislators [indiscernible] control [indiscernible] kind of what has been substitutes [indiscernible] up to where [indiscernible] in Florida Chemical looking for better chemical [indiscernible] for [indiscernible]. The question on the [indiscernible] there happens. We need a lot more than just Permian kind of basin [indiscernible] Permian, as before [indiscernible] so the timeframe is really going for the [indiscernible] out day every day [indiscernible] before the merger. [indiscernible]. And more involved every day in [indiscernible] but that's the best thing for us to see how we continue [indiscernible]
John W. Chisholm
Maybe we have time for one more and then I can shut down time. On the bus, at lunch, feel free to ask more. Anything else here? Chris will give us the logistics.
All right. Hold on a second. Before that, this concludes the webcast. Thank you, all, for joining us, and have a good rest of your day.
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