Good day ladies and gentlemen. Thank you for standing by. Welcome to the Heckmann Corporation fourth quarter and full year 2012 conference call. [Operator Instructions] I would now like to turn the conference over to Ms. Brandi Piacente. Please go ahead, ma’am.

Thank you, operator. Good afternoon everyone, and thank you for joining us to discuss Heckmann Corporation's 2012 fourth quarter and full year financial and operating results. Some of the comments we will make today are forward-looking. Generally, the words aim, anticipate, believe, could, estimate, expect, intend, may, plan, project, should, will be, will continue, will likely result, would and similar expressions identify forward-looking statements. These statements involve a number of other risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. These risks and uncertainties include a variety of factors, some of which are beyond our control. These forward-looking statements speak as of today, and you should not rely on them as representing our views in the future. We undertake no obligation to update these statements after this call. For a more detailed described of risk factors, please refer to our filings with the United States Securities and Exchange Commission, including our Annual Report on Form 10-K, as well as our current report on form 8-K and any amendments to these filings, as well as our earnings release posted on the Heckmann Corporation website, for a more detailed description of the risk factors that may affect our results. Copies of these documents may be obtained from the SEC or by visiting the Investor Relations section of our website, www.heckmanncorp.com. Also, please note that certain financial measures we may use on this call, such as adjusted EBITDA, earnings before interest, tax, depreciation and amortization, are non-GAAP measures. Please see our press release for a reconciliation of these non-GAAP financial measures to GAAP. Joining us on the call today from Heckmann Corporation are Dick Heckmann, executive chairman; Mark Johnsrud, chief executive officer; and Jay Parkinson, chief financial officer. And with that, I would now like to turn the call over to Dick Heckmann.

Good afternoon everyone, and thanks for joining us for our year-end call. I’m going to give you an overview of the year-end and the fourth quarter and then turn the call over to Jay Parkinson, our chief financial officer, who will give you detailed financial review and commentary. Mark Johnsrud, who became chief executive officer upon the closing of our merger with Power Fuels, will then discuss what he’s seeing in the Bakken and other shales and then will discuss our strategy going forward. 2012 was a record year in every respect. We completed two transformational transactions, the TFI acquisition in April, which is included in our last three quarters only, and the Power Fuels merger, which is included in the last month of the year. 2012 revenue grew over 124% to $352 million from $157 million last year. 2012 adjusted EBITDA grew 116% to almost $62 million from $28.5 million in 2011, and fourth quarter revenue grew 119% to $113 million from $52 million last year with fourth quarter adjusted EBITDA growing 256% to $15 million from $4 million in 2011. Our liquidity increased significantly through our expanding bank facility, and we are generating cash quarterly. Our leverage declined significantly to a debt to EBITDA ratio of approximately 2.6:1. We now operate in every significant shale across the country, with 70% of our energy related business as a result of oil production and 30% from natural gas production. We’re in 26 states with approximately 3,000 employees and have grown into the leader of a brand new business segment, the environmental solutions segment, of the energy business. In four years, we will have grown revenues from $15 million, to $157 million, to $352 million, and this year to over $750 million, or more than 50 times. Total assets are over $1.6 billion, with total equity of approximately $850 million and total debt of approximately $565 million, $100 million of which is unsecured and without maintenance covenants, leaving us lots of room to continue growing. The guidance today does not assume any acquisitions, which we all know is unlikely. We have certainly taken a breather from external growth since the merger to work on integration, and we do now see several areas of potential synergies to capture. We put a new 23-page investor presentation on our website at heckmanncorp.com, and while we won’t read it to you today, we will refer to it during the call. We intend to use this at investor conferences coming up, including tomorrow, but we’ll take a couple of slides out of order to provide more emphasis and clarity for this call. We are not nearly hitting on all cylinders yet, not close, but that will come with time and we’ll get there. I’ll be back later in the presentation to talk about integration, our business, and our rebranding initiatives, and then we’ll take your questions. Jay?

Thanks, Dick. If I could ask everyone to please turn to page four of the presentation that was posted on our website, I’d like to start on page four by giving a summary review of the full year and the fourth quarter. 2012 was a transformative year for the company. Revenue increased substantially to $352 million. If you pro forma that for a full year of the Power Fuels and the TFI transactions, that revenue number is $715 million. Adjusted EBITDA grew as well, to $62 million for the year, and again, looking at that pro forma combined, for the Power Fuels/TFI, a full year of that, adjusted EBITDA was $210 million. We are a national company. We operate in 26 states, all major shale basins. Q4 specifically was what I would term a transitional quarter. The Power Fuels merger closed on November 30, so the quarter includes only one month of results from Power Fuels. And as one might expect, given the amount of activity, there was a number of non-recurring items, accruals, deal and integration expense, and a tax benefit from a valuation allowance reversal, which I’ll talk about a little later. We anticipated a slowing level of activity in the second half of 2012. Drilling efficiencies for [ENT] companies pulled capex forward in the year. Midyear, clients had spent over half of their budgets, and come the fall, at the time of the fiscal cliff and the election, clients were just not willing to increase budgets to maintain activity levels. We got in front of these issues. We reduced capex. The total capex line for the company in the second half of 2012 was $11.8 million. We also built cash in both the third and fourth quarter, and we strengthened our balance sheet. Today we have over…

Thanks, Jay, and again, given the fact that this is an investor presentation, and a few of these slides are out of order, if you want to refer to page eight of the investor presentation, you’ll get a picture of our business and how we see it expanding. We now have lots of delivery and collection with our 1,200 trucks, 200 rail cars, 100 miles of pipeline, and 6,100 tanks. We have treatment capabilities in spades at TFI and four locations in the shale business. We have substantial recycling capabilities at TFI, and have begun several initiatives with major customers to recycle and reuse frack, flowback, and produced water for further fracking. These initiatives are in the early stage, but we believe will quickly begin to bear fruit. And clearly the future of this business will center around recycle and reuse, which requires lots of collection, storage, and delivery, which is now our [power alley]. On the disposal side, we now operate 46 liquid waste disposal sites with more additional permits. We’re looking at expanding disposal to include solid waste generated at the customer’s well site, and at our own sites. So page eight is fairly good picture of where we are and where we’re headed. Page 14 of the investor presentation gives you a great look at some of the key drivers in our business, and we think gives you some texture on our position that rig count does not necessarily indicate activity growth. It also shows that we operate in seven of the eight shale basins in which there is projected growth in 2013. Mark’s now going to bring you up to date on what we see, particularly in the Bakken, where we have approximately half of our resources. Mark?

Thank you, Dick. I want to just take a minute and give you a quick snapshot of the Bakken. Today, the Bakken produces over 700,000 barrels of oil and is forecast to produce over 1 million barrels of oil a day by April of 2014. Now, think back a little bit. In 2005, it was only 100,000 barrels a day. Absolutely a substantial change. Current rig count is 193 rigs between North Dakota and Montana. The North Dakota Mineral Resources Department is forecasting, by June of this year, that we’ll be back over 200 rigs. Rigs are becoming much more efficient today than they were in the past, and that can be measured from spud to spud, days to drill the well, and we really look at more of a matrix of number of wells drilled per year. And I think that’s extremely important, because this is, again, kind of a paradigm shift in what we used to look at versus what we’re going to be looking at going forward. Kind of on a macro basis, we drilled 5,000 wells, and on a very conservative basis, the forecast is between 40,000 and 50,000 wells, as fully developed. Now, if you really take a look at some of the new technologies and the amount of capital expenditures, for 2013 companies are spending on increased or reduced spacings that could potentially increase the number of wells drilled on any spacing. That multiple could be anywhere from 2 times to 8 times as many wells. So I think we’re very early in where we ultimately go in this. There’s one more real important factor when we look at the economics of the Bakken, and that is that the increased rail transportation capacity has made a monumental difference with regard to the spread between NYMEX and the crude oil price that the marketer receives. That spread last summer was as high as $20 and now is reported to be somewhere between $5 and $7. And when you look at 700,000 barrels a day, it turns into a lot of money. So we think that that money just comes back to the producer. It absolutely helps the economics.

Thanks, Mark. And finally, we’re announcing today a renaming and rebranding strategy. As a result of our acquisition strategy, we have over a dozen different company names, with four significantly used names: Heckmann Corp., HWR, Power Fuels, and Thermo Fluids. Every customer we talk to wants an integrated, nationally based, full service solutions provider. Frankly, all the obvious names are taken and trademarked, and the URLs are unavailable. Again, when you have time, go to our website and look at pages 16 to 21, at the rationale and the origin of the name Nuverra Environmental Solutions, which we have chosen. Our website URL will be nuverra.com. Our new NYSE ticker symbol will be NES. Our corporate tagline will be “We put our energy behind sustainability.” And, subject to shareholder approval on May 8, the company will begin trading under the new symbol on May 13. We think the benefit of well over 8,000 billboards - that’s our trucks, tanks, and facilities - far outweighs the short term pain caused by a name change, and that as we continue to grow and add additional companies and services to the portfolio, a fully integrated one-stop shop is exactly what our customer base wants. The good news is that we’re in the front of the greatest domestic competitive advantage of generation: domestic energy independence. So we believe if there’s ever a time to set a new branding strategy, it’s now. So let me close by saying we very much appreciate our shareholder confidence in the long road to creating a company built to last. 50 times revenue in four years is a truly remarkable feat engineered by our great team, but please know that we see a long runway ahead. Now we’ll open it up for questions.

[Operator instructions.] And our first question comes from Scott Graham with Jeffries. Please go ahead. Scott Graham - Jefferies & Company: I had three general questions. The first was, if you can give us maybe a little bit more color. In past conference calls, you’ve given us a couple of little details on what you’re doing in each shale, and kind of what you’re seeing sequentially. Maybe the Bakken, obviously a little bit more time on that, from Mark, if possible, but also the other shales, and what those strategies are doing in positioning you guys, how it’s positioning you, to gain share in those shales.

We’ll look at the Utica first. The Utica is new. We are moving towards the Utica with a couple of customers right now, and what we want to be providing is, as Jay and Dick talked about, is kind of the whole basket of solutions, because what they’re asking us for is full cycle. They want us to take care of their liquids, their solids, all the product that moves on and off their location. And that’s what we’re doing, and we will be doing that in the Utica. By the way, we just ended up receiving another disposal permit in the last 30 days, in that basin. We go into the Marcellus, and we have two or three large customers there. All of them are having I wouldn’t say an aggressive plan, but they’re going to be increasing their program fairly significantly. What that’s going to really help us on is the reuse and recycle, because as we all know, production water is a real issue there, and hauling the production water from Pennsylvania to Ohio is extremely expensive. So we can reuse and recycle it, which will run through our EWS plant. We think that’s going to be very beneficial. We’re a little bit behind through the first quarter there, and that’s mostly because they’ve had a lot of snow in Pennsylvania. This is probably the toughest winter they’ve had in several years. And as we work for some of the larger companies, they’re a little more cautious about snow days. And everybody’s very concerned about the health and safety environment. And then the reality is, today, it’s environment health and safety. We looked at the Haynesville, would be the next one, and we’re seeing modest growth. I think we’re starting to take a look at some of…

No, I don’t think so, Scott. I think if you kind of look at the midpoint on both of those, I think in terms of where we see the revolver, or the credit facility going, I think we see deleveraging there. It will obviously be a mix in how we look at some financing on some of the various assets coming on. I think the other thing I would comment is that I think we’ve talked a fair amount of the optionality we see on capex. There’s some fluctuation on that, depending on where we come out in the band on the guidance. And keep in mind, the other function we have here, and we talked about it, is we have the opportunity to offset some of the cash taxes as well, which also improves the liquidity. So from our math, there’s deleveraging on the business going forward. Scott Graham - Jefferies & Company: All right. Maybe we can talk about that offline a little bit more specifically. The last question is about TFI. It’s a terrific asset that you have there. There’s synergies with both businesses. There are acquisitions out there for you. Kind of what’s the plan for TFI in 2013? Are you looking at acquisitions as prominently there as you are in the other businesses?

I think that’s a great question. Without question, we really like the business, and what we’re doing is, we are actively looking at what fits in our footprint. You know, it’s really interesting, Scott, if you kind of step back, all of the changes that are going on kind of in the Bakken and other places, by moving crude, it is really changing that business. And so the regional refining and some of the other pieces that are different in that industry are starting to really become a major impact. And we’re trying to evaluate all of that, and make sure that we’re strategically making the right decisions.

Yeah, I would add to that, Scott, that at this point I think we’re really glad we don’t have a lot of fixed assets in that business, because as Mark rightly pointed out, with all this oil moving around this country now, I don’t think anybody can see far enough ahead to see where you’d want to have a big capital equipment investment. But as recently as this morning, we were talking about acquisitions in that business.

And our next question comes from Brian Post with Roth Capital Partners. Please go ahead, sir.

More on the cost side, looking at gross margin, it ticked down a bit on a quarter to quarter basis. Any additional commentary there? Maybe if you break it out on the individual legacy Heckmann business to Power Fuels business, and the TFI business, any additional commentary or color on how those trended versus on a sequential basis?

I would say, by and large, obviously there was some margin compression in the fourth quarter. Really what we saw to a great degree, and I think it goes across both of the shale and market businesses, you just saw the pace of activity slow. And the short answer is you lose some operating leverage with that. I think that was a pretty consistent theme I’d say, as it relates to pricing base. And there was some differences in the various basins. Obviously we talked about the Power Fuels, the Bakken area, exceeded what we were expecting. But there was clearly just general activity slowdown in terms of volumes across the portfolio, and that impacted margin.

And a follow up about your customer base, if I may. Given that you’ve had a few months of the Power Fuels acquisition, have you seen any examples or evidence of customers you had in the past, maybe in the Eagle Ford, Haynesville, Marcellus, excited and jumping over to you or expanding their business now that you guys are operating in the Bakken?

We are definitely seeing that. We have one of our largest customers in the Bakken that we are going to be working for in the Utica. And what they’ve told us is they want to make sure that they’re leveraging off of what we bring them. You know, in the past it was always we thought we were leveraging off of them, but I think what they’re doing is when we provide the right [HS&E] program, the right equipment, the right structure, and the right suite of services, they want to use us in all basins. And so I would say today that we probably have eight or nine customers that we are working with on a multiple basin, and then also, from kind of a legacy Heckmann, legacy Power Fuels, we’re looking at how we operate together.

And our next question comes from Evan Templeton with Jefferies. Please go ahead.

Just wondering if you could maybe go into the 2013 capital budget a little bit more. What portion of that is maintenance? And as well, how it’s allocated to the different divisions?

It’s probably, I would say, by and large, going to be pretty heavily weighted to the oil shale segments. The TFI business we’ve talked about, absent some of the infill acquisitions, that’s not a business that requires a tremendous amount of capital. There’s a lot of free cash flow going on there. I would say, on the maintenance versus growth side, you’re probably in the ballpark of 60% maintenance. Again, the maintenance line, in terms of how we pull that lever, will be a lot of how we see the market develop. Because I think as we’ve proven the last two quarters, given the young age of our fleet, given the fact that we can move the fleet around, and so mobile, there is a lot of optionality against that, depending on where we see the opportunities in the year.

And then as far as that growth component, is that allocated towards specific projects? And would that be mostly in disposal wells? How should we think about that?

Some of it will be project based to meet anticipated volume pickups in some of the oil basins. There are some additional trucks and trailers. Mark talked about some opportunities we’ve [unintelligible] to deploy capital at really accretive returns to create some efficiencies in some of our existing fleet. We like the return profile of those projects. And then the other thing, as we’ve talked about, in terms of building out the solutions based strategy, there’s some opportunities, project based, in some of the treatment and recycling side, which I think will be interesting. I think on the final end of the stool, if you think about on the disposal side, something we’re going to look at really hard there is going to be opportunities on the solid waste disposal. So that would be project based. But we’re seeing some real opportunities to get after on that front.

And then I guess the last question, I think there was a mention of you having some rail car shortages and logistical issues? How do you see that playing out?

Excuse me, I did not mean that we were having that problem. We’re talking about nationwide, that there is a tremendous demand for rail cars, just to move crude oil. And at TFI, we have 220 rail cars today leased. And those are moving used motor oil to re-refining capacity. And because we’re moving small, we’re moving anywhere from 2 to 10 rail cars in a group, versus today what’s going on by unit trains or shuttle trains, are moving 108 at a time. So I think there’s a little bit of a shift, and just by the number of turns they’re able to get in a year, it’s kind of changing the economics of moving oil, or at least the used motor oil, compared to what it was a year or two ago.

I would add to that that, you know, it’s interesting, you watch the fluctuation in gas prices, which is always a surprise, but I don’t think anybody three years ago thought we were going to have traffic jams of oil tankers dragging oil around this country. But that’s what you’ve got.

And our next question comes from Gary Sweeney with Boenning. Please go ahead. Gerard Sweeney - Boenning & Scattergood: A couple of questions for you. You’ve spoken about an inflection point on the capex side, but you’ve also spoken about, in the past, having a lot of costs bringing fibers up to speed, dual drivers, getting them certified, etc. When do you sort of hit an inflection point when that passes? Or has that occurred? And when do we start seeing that sort of flow through to the gross margin line?

You know, that’s just a percentage of how big you get. I mean, two years ago, 30 drivers was a really big load to carry for 90 days, until they got certified. This year we may add as many as 200 drivers, and it won’t be as big a load as the 30 were a couple of years ago. But you’re always going to have, until you get to a size where 200 drivers is a rounding error, you’re always going to have to deal with it. But I think the answer to your question is, the bigger we get, that component of some cost for growth will become smaller. Gerard Sweeney - Boenning & Scattergood: Also, I think that as capex slows, I imagine you’re not going to be buying as many trucks. Wouldn’t that also carry through in terms of drivers catching up to the number [cross talk]?

What that does, though, is we’ll take a look at efficiencies. Then we’ll start to try to make sure that our fleet, we will try to maximize the number of drivers per truck. And with the different jobs they have. So we’re going to make sure that we’re able to take care of what our customers want, but then we’ll maximize our utilization of equipment. And so when you’re first starting, you’re going to need enough equipment to get the job done. As you come back, and you start to maximize what you can do, then you can start to double shift the number of drivers in that truck, and ultimately run that truck 24 hours a day for whatever’s legal with regard to the DOT requirements. Because obviously we follow all the OT requirements. Gerard Sweeney - Boenning & Scattergood : Sure, that’s sort of what I’m getting at. At what point do you start getting that efficiency? You have the several thousand trucks you have, and then are you going to start hot seating them? Or you’re not carrying the excess drivers?

Today I would say that we have more opportunity to increase drivers without adding additional trucks. Now, there’s going to be certain basins that have specialized configuration, that one set of equipment doesn’t work in each basin. So as we go to the Marcellus, because of the hills and the activity, you have a very finite set of equipment that you can use in that basin. Gerard Sweeney - Boenning & Scattergood : And then my other question was on the efficiency in drilling. Understand that they were taking 30 days spud to spud, now it’s down to 20. And I guess some of the [E&P] guys are moving - whatever they’re called, batch drilling, different names - but once you move to that type of work, wouldn’t that reduce some of the logistics required, because…

Actually, it increases the amount of logistics because what everybody’s also looking for is from spud to the first day that the well is actually in production. So the more they can reduce that, it helps their cash flow. When we were originally trying to get started several years ago, there was always lag times. Now there’s a very tight schedule that’s being run, so they can optimize the number of days the rig is drilling when the workover rate comes on to make sure that that’s scheduled to be in and out. And so the quicker they can go from spud to cash flow we’re seeing a very hard push on that. So when you really look at it, the number of days reduced from the drilling side, what that does is it makes us in a month period of time have more work to do, on the completion side. Gerard Sweeney - Boenning & Scattergood : Wouldn’t the water stay on the pad? A large portion of it is sourcing water and taking it off, and disposal, so if you’re using batch drilling, I know sometimes in the Marcellus, oftentimes, they’ll dilute the water, but it generally stays in the same vicinity, or even on the same pad. Then they just reuse it.

That will happen on the water they’re going to drill with. But most of that is only when the drills are surfaced. From below surface, they’re using some sort of drilling fluid that gets reused from well to well. But that’s not where the majority of the fluid is used. It’s when they’re fracking it. That’s when the majority of the water’s used. That’s when a large volume is used. Gerard Sweeney - Boenning & Scattergood : Would you be able to give a breakout of what equipment is in what basin?

We do not release that publicly.

And our next question comes from Brian Uhlmer with Global Hunter. Please go ahead sir.

I was curious, looking at your guidance, kind of some of the things you talk about, it seems like it’s going to be heavily back half weighted, and you’re talking about issues subsiding in Q1. How do you look at the progression to go from Q1 through to Q4, from where we ended the year? Obviously you talked about the Bakken here, the rig count still at a hair over 200. So how do you look at that progression? Is there more revenue progression, or more margin progression, and what basins are driving the increase throughout the year?

Let me start first with the margin. I think the margin, by and large, kind of where you are at the midpoint, will be relatively consistent throughout the year, absent Q1. Again, we had some down times, which impacted activity, and obviously lose some operating leverage there. Setting that aside, I think the progression will actually be relatively consistent with the example I gave of a customer, in terms of how they’re splitting out their capital kind of first half to second half. And I think it will be a pretty steady ramp up quarterly throughout the year. But I think if you kind of blend the first half and the second half, I think that mix will actually be relatively consistent.

Okay. Now, on your internal controls, and Jay, you’ve taken over the reins as CFO, but last year’s EBITDA guidance was missed by about 30% all in, on the low end of the range. I guess has there been changes of how you look at assessing the guidance and giving out your guidance from what you did on the prior year? Or was last year kind of an anomaly with that back half fall apart that we had, and the oil patch specifically?

I’ll comment at a little bit of a higher level on last year, and a little more on a granular level about this year. Starting with last year, I think what we saw in the second half of the year, and was talked about as early as the second quarter, you did see what I would call a fairly severe dislocation in the gas markets, which actually had a double edged effect. Not only did it affect activity in the gas markets, but a lot of those assets moved to approximate oil rich markets. It’s not very hard to move assets from Dallas area down to San Antonio. So that’s what you saw affect some of the mid-continent. It didn’t affect the Bakken as well. And then also, by and large, in the second half of the year, we did see what we talked about, just the general slowdown. I’d say if we think about it this year, we’ve really expanded some of the internal capabilities and controls. We have a director of finance. We’ve hired a lot of people. So we’re very focused on continuing to have a company that matches the size we are today, the scale we are today. And we feel very good about where we are from a control perspective.

Now, moving on to the operations, for Mark or Dick, you mentioned some acquisition opportunities, and then being familiar with the Bakken, obviously there’s a small E&P up there with their own midstream water pipeline, that tags into their own disposal well network. How do you see that, number one, as a threat to your business? And number two, as a potential opportunity for you to do something similar moving forward?

We’ve taken a look at some of the people that have talked about putting in pipelines, and especially when you take a look at the production pipelines, we think that that’s something that when you really run the economics, it becomes pretty tough to do it, from my standpoint anyway, especially when you take a look at the cost. One more thing that is becoming harder and harder to do is to get easements. And so just to get easement for major pipelines is getting extremely tough, and so when you’re putting in pipelines, multiple pipelines, and water pipelines, I really see that as a big issue.

And I would add to that that you’ve got to remember that in Texas and Louisiana, these folks have been running pipeline since the beginning of the country. And there’s pipelines everywhere down there, and pipeline easements are a fairly common phenomenon. Not so much in North Dakota and further. We go three feet deep in Texas. You’re going to have to go real deep in North Dakota, because of the frost line, and that increases the cost dramatically. So the first thing we did in our early days of discussion with Mark was is there any way to duplicate a pipeline situation like we have in Louisiana, and we quickly came to the conclusion that it was going to be very expensive, and a far bigger risk than it is down there.

And finally, following up on another question on pad fracking and line pits, that is an issue in some of the Texas markets, with temporary piping and flowing from one line to the next, to reuse the frack water. Is that less of an issue up in the Bakken, as it’s primarily a closed frack tank market with the heated frack tanks? Is that the main reason why that’s less of a risk there?

The main reason is because the chlorides are so high in the flowback water that until recently you have not been able to use the flowback water to any high percentage as far as in the next frack. And so there’s some chemistry involved with the gels that do not work with salt water. So it is a big issue in the Bakken today. There’s some new technology that is out today that says we may be able to use salt water for fracking, and if that’s the case, we think that’s very positive for us. In comparison to Texas, they’re able to use a different fracking procedure, where the chlorides are lower in the water. So they can reuse it, but most of that water has to be treated before it can be reused. And we actually have a treatment facility in Texas that can be used, and is being used, for treating of water, that will ultimately be used for fracking.

Right, and that’s more of a centralized facility versus…

The thing about all of this is that if they’re going to use salt water, they’re going to have to treat it, and we just don’t see, certainly at this stage of technology, this being done on very many pads. It’s going to be centrally treated, which means it’s going to be hauled to a central treatment facility. It’s going to be treated, then it’s going to be hauled back to frack. And by the way, Mark’s not sitting on his hands up there. We’ve been involved in this for some time. We see the advent of the reuse of salt water as being a huge advantage to our business, because you’ve got to haul it, and you’ve got to treat it, and you’ve got to hold it, and you’ve got to store it.

I think one of the issues that comes up is if it’s even on a pad location, when the well’s being flowed back, you’re going to have to treat the water, but then you’re going to have to store it. Then you’re going to have to make sure you have the right chemistry to be able to refrack, and with the size of the pads that are relatively small, there’s just not enough room on location to do all this work. And then I think there also becomes a safety issue, if you were going to try to do this, to flow back a well, to store the water, treat the water, and frack in the same location. I think that could potentially be causing some safety concerns.

Okay, I think that’s the last question that’s come up on our screen here, so once again, you’ve got 23 pages on the website that you can go and review everything that we’ve said. As we showed in the release announcing the conference call, there’s a lot of conferences coming up that we hope to see you at, and answer whatever questions you have. Appreciate your time, and see you on the road.