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Greetings, and welcome to the Keane Group Second Quarter 2018 Financial and Operating Results Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Kevin McDonald, Executive Vice President and General Counsel. Thank you, you may begin.
Good morning, and welcome to Keane Group's Second Quarter 2018 Conference Call. Joining me today are James Stewart, Chairman and Chief Executive Officer; and Greg Powell, President and Chief Financial Officer. As a reminder, some of our comments today will include forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995, reflecting Keane's views about future events. These matters involve risks and uncertainties that could cause our actual results to materially differ from our forward-looking statements. The company's actual results could differ materially due to several important factors, including those risks and uncertainties described in the company's Form 10-K for the year ended December 31, 2017, recent current reports on Form 8-K and other Securities and Exchange Commission filings, many of which are beyond the company's control. We undertake no obligation to revise or update publicly any forward-looking statements for any reason. Additionally, we may refer to non-GAAP measures, including adjusted EBITDA and adjusted gross profit during the call. Please refer to our public filings and disclosures, including our earnings press release for definitions of our non-GAAP measures and the reconciliation of these measures to the directly comparable GAAP measures. With that, I will turn the call over to James.
Thank you, Kevin, and thanks, everyone for joining us on the call this morning. During the second quarter, we realized adjusted EBITDA of more than $111 million, maintained full utilization on our fleet, placed into service our 27th fleet and continued to ramp our cementing business. From a capital and capital return perspective, we entered into a favorable new term-loan facility and completed more than $40 million of stock repurchases. Overall, the quarter was strong. Turning to the market, we continued to view the macro environment for the completion services industry as constructive. The market environment we experienced throughout much of the second quarter was representative of the strength we continue to experience today. Pressure pumping is benefiting from increased customer demand, supply tightness for quality completions and contingent growth in service intensity. While the current market is constructive and the long-term outlook robust, there has been discussion across the industry in recent weeks regarding a potential shortage of ample pipeline takeaway capacity in the Permian. And the possibility for it to drive a slowdown in completions activity in the intermediate term. Taking a step back and holding aside for a moment a view of the potential implications of this dynamic, we think it's important to put these issues in context. What we're talking about here is a growth problem for the largest, most prolific and economic oil basin in the U.S. When we started Keane back in 2011, oil production in the Permian Basin was below 1 million barrels per day. Today this has increased to nearly 3.5 million barrels per day and is still growing. At the root of it, we consider these potential challenges as transitory growing pains. While we've heard a lot about potential takeaway issues, we've yet to see them manifest into any current or known material impact to our business and our customers. We remain in active dialogue with each of our customers and we are hearing consistent message in response. They have not changed plans and have communicated to us that they have adequate takeaway capacity in place. So that's what we're seeing and hearing today. Looking ahead, we acknowledge there could be a period in which the Permian faces a temporary shortage in takeaway capacity, resulting in what we had described as an air pocket for the broader U.S. energy market. The key questions in this potential scenario are, what is the magnitude of the shortfall and how long does it last? Complicating the discussion are the many factors that influence the ultimate impact to the industry and its timing, including alternative methods of transportation like potential reallocation of activity to other basins, company-specific completions decisions and other factors. At the same time, new pipeline capacity is under development and expected to come online throughout 2019 and 2020. We believe it is important to consider the situation in the context of these many variables. In all scenarios, we view this Permian takeaway situation, like others we've faced, to be transitory. We remain bullish on the market overall, and are optimistic about how Keane is positioned in both the near and long term. We summarize our conference highlighting 2 main factors. First is our strategy of partnering with top-tier customers under dedicated agreements. We followed this strategy since the day we started Keane and now, more than ever, believe it's the right approach. We have also discussed that dedicated contract strategies of industry players vary and have explained extensively our approach to partnering closely with our customers. We believe our model is more resilient, given our role as a critical manufacturing arm for our customers' production. Our customers are like us in that they are focused on efficiency and returns, making their cost of change high and the strength of our relationships more robust for transitory issue cycles and over the long term. And second, perhaps the most direct source of insulation we have against temporary market factors is the mere fact that who we partner with. Our blue-chip customers take through-cycle views on their completions programs, have sufficient firm takeaway agreements in place to support their growth for years to come and supply chains that allow them to navigate dislocations as they arrive. The caliber of our customer book is second to none. We've expressed the importance of aligning with the right customers, ones that share in the same values enabling us to deliver the high levels of efficiency and safety performance that we collectively require. Regardless of timing and duration of any potential impacts, we view these as transitory challenges. At the same time, we believe any potential dislocations would be supportive of the frac market and the commodity price environment. We believe this for 2 key reasons. First, we expect drilling activity by EMPs to be somewhat resilient, driven by a number of factors, including their desire to retain super spec rigs. As a result, we believe certain operators are likely to continue to drill and to defer completions, in turn growing the number of DUCs and supporting a base of pent-up demand for frac services. This also bodes well for drilling and related services, such as the growth in our cement platform. And second, we remain encouraged by the supply side of equation. Service intensity and increased pumping teams are requiring more horsepower on the well site and on the maintenance rotation. In addition, equipment age and condition are leading to performance challenges on the sizable portion of active fleets. As a result, we continue to believe that a significant portion of announced newbuild horsepower will be used as replacement. And finally, over the last several quarters, we have been relatively insulated from horsepower shuffling. This is due to our robust partnership with customers on a dedicated agreement delivering value through safety, efficiency, continuous improvement and technology. Before handing over to Greg, I want to highlight an exciting announcement we've recently made. We expect to bolster our Executive team with addition of Robert Drummond as Chief Executive Officer of Keane. For those of you not already familiar with Robert, he is a proven leader with world-class completions experience. Robert most recently, served as Chief Executive Officer of Key Energy. Prior to that, Robert spent more 30 years at Schlumberger, including serving as the company's President of North America. Robert and I know one another for most of our careers, including when we started together as new engineers over 30 years ago. I know I speak on behalf of Greg and the rest of our management team, when I say that Robert is a great fit for our company, customers and employees. I'm truly excited to have him onboard starting in mid-August and look forward to working closely with him in my new role as Executive Chairman. With that, I'd now like to turn the call over to Greg.
At the beginning of June, we deployed the first of our 3 newbuild fleets under a dedicated agreement for an existing customer in the Marcellus/Utica. The second of our newbuild fleets was deployed in the Permian basin under a dedicated agreement with a new customer early in the third quarter. Yesterday, we announced entering into a dedicated agreement for the third of our newbuild fleets. The fleet will support the activity of an existing customer in the Permian Basin as an -- and is expected to be deployed in the fourth quarter of 2018. When we first announced our newbuild fleet expansion at the end of 2017, we commented on the attractive lead times we were able to secure. Our success in entering into dedicated agreements on all fleets partnering with high-quality customers and deploying 2 of the 3, all within 6 months and ahead of schedule, reflects the quality of our relationships and execution by our team. All 3 fleets are earning or will earn annualized adjusted gross profit per fleet of greater than $20 million. Turning now to a fleet overview. We averaged 26.3 hydraulic fracturing fleets during the second quarter of 2018, maintaining full utilization throughout the quarter and exiting the period with 27 deployed fleets. We continue to be pleased with how we're positioned from an operating footprint perspective. Today, approximately 50% of our horsepower is deployed in the Permian, roughly 35% of our fleet is working in the Marcellus/Utica with the remaining 15% operating in the Bakken and Eagle Ford. Total revenue for the second quarter totaled $578.5 million, an increase of 13% compared to the first quarter total of $513 million. This pace of revenue growth significantly outperformed the 7.5% sequential increase in average rig count experienced during the second quarter. Our second quarter revenue performance was driven by price increases from contract reopeners on a portion of our portfolio, efficiency improvements following the abatement of transitory issues experienced in the first quarter of 2018 and contribution from our newbuild fleet added in June. Revenue from our Other Services segment, which reflects our cementing operations, totaled $8.6 million for the second quarter of 2018. This represents a sequential increase of approximately $3 million or more than 50%, reflecting the continuing ramp of our cementing operations. We continue to be encouraged by the level of interest we're seeing in the business from both existing and new customers. We are beginning to see the benefits of greater scale as we roll out new units in the Permian and Bakken, and expect our financial performance during the third and fourth quarters of the year to reflect the further ramp in utilization and profitability. The company adjusted EBITDA in the second quarter totaled $111.3 million, an increase of approximately $20 million, as compared to the $91.3 million, we reported in the prior quarter. Adjusted gross profit totaled $130.8 million for the second quarter compared to $109.6 million in the prior quarter. On a per fleet basis, annualized adjusted gross profit was $20 million, up from $17 million in the prior quarter, and as compared to our first quarter normalized result of approximately $18 million. Adjusted EBITDA for the second quarter excludes approximately $7.9 million of one-time expenses, of which $4 million was for noncash stock compensation, $2.7 million was for a noncash book loss on the sale of idle real estate acquired as part of the Trican acquisition, and approximately $1 million for fees related to establishing initial ratings associated with our new term loan. Selling, general and administrative expenses totaled $24.1 million for the second quarter compared to $33.9 million in the prior quarter. Excluding one-time items, SG&A totaled $18.9 million compared to $17.8 million in the first quarter of 2018. One-time SG&A items for the second quarter included noncash stock compensation expense and rating agency fees. We continue to run at leading SG&A efficiency levels with second quarter SG&A excluding one-time items representing the 3.3% of total company revenues. Turning now to M&A. We acquired approximately 90,000 hydraulic horsepower from Refinery Specialties in a deal that we closed last week. Total consideration for the transaction was $34.6 million or roughly $400 per horsepower. This equipment is high quality, well-maintained, fit for duty across Keane's operating footprint and has been operating at low utilization levels in the North Eagle Ford. The acquired equipment will be deployed in 3 strategic ways. First, a portion of the horsepower will be used to replace equipment damaged in the fire we previously announced. The equipment impacted at the incident was insured at replacement cost and we expect to recover proceeds in the third quarter of 2018. Second, a portion of the horsepower will be used to temporarily support our existing maintenance assets. And third, while these assets don't have agreements in place today that fit our dedicated model approach, we will seek a new home for them with the right dedicated partner, resulting in 1 additional frac fleet in the future. Each acquisition we've completed in our history has served a key strategic purpose, and while small, this acquisition is no different. The deal is consistent with our view on the need for consolidation and we believe it reflects yet another example of our unique ability to find and successfully execute accretive deals. We continue to search for deals of all sizes and have the balance sheet, track record and competency to execute. Turning to the balance sheet. We exited the second quarter with cash and cash equivalents of $109.5 million, up from $95.5 million at the end of the first quarter. We generated positive operating cash flow of approximately $109.2 million for the second quarter. Capital expenditures during the second quarter of 2018 totaled $75.4 million of cash driven by spending associated with our newbuild fleets as well as normal maintenance CapEx. Total debt at the end of the second quarter was approximately $341.3 million, net of unamortized deferred charges and excluding capital lease obligations, up from $274.7 million at the end of the first quarter. The sequential increase in our debt position was driven by our new term-loan facility completed in May. This new $350 million term loan facility was used to repay our existing $282.5 million term-loan facility. During the second quarter, we used cash on hand to fund the $19.9 million cash payment of our CVR associated with our RockPile acquisition and $40.1 million for stock repurchases executed during the quarter. We are pleased to have completed our new term loan, which extended maturity and reduced our interest cost, which is expected to drive approximately $4 million of annualized interest savings. On an annualized run-rate basis, second quarter adjusted EBITDA was approximately $445 million, reflecting a leverage ratio of approximately 0.8x, unchanged as compared to the prior quarter. Net debt at the end of the second quarter was $232 million. We exited the second quarter with total available liquidity of approximately $324 million, which includes availability under our asset-based credit facility. We remain committed to our three-pronged capital allocation approach, which includes investing in growth, maintaining and improving our balance sheet and capital return. Our $100 million stock repurchase program became effective at the start of the second quarter, and we quickly executed on our plan to return value to shareholders through the repurchase of our shares. During the second quarter, we completed approximately $40 million of stock repurchases, representing approximately 2.6 million shares. We've emphasized our belief in capital return and today are reiterating our intention to opportunistically execute on additional repurchases over the near term. In fact, we are pleased to report that last week, our board authorized a refresh in our repurchase program, reloading our available purchasing capacity back to a total of $100 million. Turning now to our outlook. For the third quarter, we expect deployed hydraulic fracturing fleets to average 27 fleets, while we work to integrate the newly acquired assets and enable the reactivation of the partially damaged fleet, targeted for the end of the third quarter. On this base, total revenues expected to range between $565 million and $590 million. On a per fleet basis, we expect annualized adjusted gross profit for the third quarter to be in line with the second quarter results, driven by the strength of our customer portfolio and dedicated agreements. For cementing, we are seeing a continued ramp in our business and expect a stronger performance during the second half of 2018. We stand by our expectation for run-rate revenue from the cementing business exiting 2018 between $70 million and $90 million in gross margins of between 20% and 25%. With that, we'd like to open up the lines for Q&A. Operator?
[Operator Instructions] Our first question is coming from Tommy Moll of Stephens.
So I wanted to start by talking about your outlook for the third quarter. So at the top line, there's a fairly wide range of outcomes that you mentioned. I was curious, what do you consider the book-ends for the range of the underlying net price in there? And then other than price, what other factors might impacted job mix, for example, sand, et cetera? And then on the bottom line, you are sticking with guidance of roughly $20 million adjusted GP per fleet per year, which is impressive, given some of the current market conditions that've impacted peers. So I was curious, what do you think gives you visibility and confidence to maintain that outlook? Does it have something to do with the dedicated fleet model versus some of the alternatives, where some of your peers have had less opportunistic outlooks for the third quarter?
Yes, thanks, Tommy. I'll try to answer those in reverse order, if you don't mind. So the insulation we're seeing so far in the second quarter and what we guided in the third quarter is primarily the customers we've aligned with. They have -- they're zealots on efficiency, they're focused on the long-term. They've got big programs. They can work through different commodity stacks, and they don't want any disruption in what they view as their manufacturing partner in their frac company. So the cost to change on those relationships is high. We're highly integrated with our engineering, all the way through to C-suite with our customers. And as a result, those relationships have longevity and stickiness to them, and that's why we have the visibility we have. On the revenue, the main driver of the revenue per fleet kind of coming down second quarter to third quarter is our adoption of local sand. As everybody knows, the mines in Winkler County and the Permian kind of stumbled as they came online. We're up to over 80% local for the fleets that we supply sand for in the Permian. We expect that to be close to 100% by the end of the third quarter. And what that does is, it doesn't impact our GP line, but it impacts the revenue line. So that's what's accounting for a nominal drop in the revenue per fleet. The pricing in the book is rock solid, as is indicative in the profitability metrics.
Got it. Then I also wanted to follow up on the capital return plans. So you mentioned the re-up on the repurchase authorization. Could you just give us a little more context on your thinking about how to deploy that? And is it fair to assume that with the stock sitting here below your average buy price in the second quarter that you'd tend to be pretty active with the buyback as we get through earnings season in the third quarter?
Yes, I think that's right. I mean, on capital allocation, I feel like we're generating enough cash flow to execute on multiple priorities, including growth. We've done organic growth with our new fleets. We had opportunistic M&A opportunity with the assets we acquired from RSI and then we're executing on the buyback program. We think these stock prices are very attractive based on what we see in both the near-term and certainly in the long-term for the viability and profitability of the business. So I think you'll see us be pretty aggressive on executing that buyback program. And we're excited that we added more capacity to it.
Our next question is coming from Sean Meakim of JPMorgan.
So maybe, if you could look a little beyond 3Q, just thinking about into year end. We have a typical seasonality. And of course, weather's a bit hard to call, but do you see any risk of customers hitting the completion programs early, shutting down for the holidays, just given E&Ps seem more inclined to stick to the calendar budget this year? Or given your customer mix, do you see that as being less of a factor for you?
Sean, that's a great question. I think, as we sit here today, it's hard to answer that, because it varies. The weather changes a little bit every year. So at the moment, I would say, it's very hard to predict what that's going to look like. But I would say, at the current outlook on the oil price, I would think we would see less of seasonal impact than we've seen in the previous years.
Okay. And certainly, very common investor concern even among frac companies with dedicated fleet models is that, as the spot market gets more challenged that there's naturally going to be bleeding of pricing pressure into those dedicated agreements. Could you maybe talk through how you could see that unfolding, if things got more challenging than you'd expect in the spot market? Or to what extent do you think that you'll be able to maintain that insulation over the next, what could be, say, 2 to 4 quarters of more difficult environment for spot-based fleets?
Yes, I mean, I think Sean, it would depend on how draconian things got. I mean, the customer decision they have to make is, if this is viewed as a transitory issue in an air pocket, and James had some prepared remarks on it's hard to predict how long that lasts or when it starts. But in a draconian scenario, you're going to see some excess capacity. But the customers -- the cost of change is very high. We've been working with these customers for a long period of time. The safety and efficiency is running at a very high-level, and customers have to decide if they want to disrupt that equation. And so far, we've been insulated from that. We've not seen a lot of competitive pressure on our dedicated agreements. And we'll just have to see how the Permian takeaway issues play out.
That's all totally fair. And just last kind of follow on to that, if I could. I think investors often try to get a gauge for, what do we think profitability looks like through cycle? You been able to hit this $20 million GP number earlier than you expected. Can you maybe give us a sense of how you see the business through cycle in terms of what would you envision as peak versus what do you considered normalized GP per fleet?
Yes, I mean, it comes down to a return profile. I mean, service intensity has gone up, so that the -- you almost have to throw maintenance CapEx into that, when you're looking at a return profile. So we're certainly not where we were in 2011, when you were seeing GP per fleets north of 30, we started to see around this level in '14 before the complex fell apart. So I'd say somewhere between 15 and 20 feels like a mid-cycle. There are certainly opportunities to give better returns given the service intensity and the amount we're spending on maintenance and CapEx. So it feels like where we are now in the 15, 16 to kind of low-20s, feels like a mid-cycle and then you're going to hit different peaks and troughs as the cycles go through.
Our next question is coming from Jud Bailey of Wells Fargo.
A question, if you could maybe talk a little bit about the differences to the extent you're seeing differences between basins. There has been a lot of talk about the Marcellus, and some E&Ps releasing crews in the back half of the year. Could you maybe give a little bit color on what you're seeing from your customer base and kind of competitive dynamics in that area?
John, the Marcellus is kind of our home base and we got a very, very strong footprint and high-quality business there. There has been some talk of some slowdown. I mean, we don't get into talk about any particular customer, but our utilization has basically remained same, and it looks like it's going to continue that for the rest of the year.
And you said, it will continue through the rest of the year, is that what you said, James?
Yes.
Second question, maybe for you or for Greg, and you mentioned consolidation and probably the desire for consolidation in the industry. Could you talk about kind of how you think about the business in terms of as kind of market trends evolve, the proper kind of size of the business or diversity or how do you think about the need to kind of get a little more scale and then how big would you think the optimal size is, do you think about in terms of horsepower, do you think about it in terms of basin exposure how do you think about ultimately growing the business and diversifying if that's important to you at all?
Yes, I mean, scale matters in the frac business, right? I mean, it's a fixed cost business. The more leverage you get on basin density, more densities, it allows you to take some bigger swings. You can take bigger swings on R&D. Look, we have avoided vertical integration all these years and 1.4 million horsepower where we're heading, we still don't think it makes, if you get 2.5 million horsepower. I think you got some more arrows in your quiver to take some bigger swings and look at bringing some things in-house that we wouldn't look at today. So scale matters in this business. It helps on profitability and leverage. So we're believers in consolidation. And anywhere, where we are now at 1.4 million, I mean, when we started the company with 30,000-horsepower, we thought getting to 1 million was a big milestone and we look around and the landscape at 1 million is fairly crowded, right? And everybody has been recapitalized. So we definitely think there needs to be consolidation. North of 2 million horsepower seems like a sweet spot, and it accomplishes some of those scale benefits, I mentioned.
Okay. And my last one, if I could slip it in. You mentioned local sand as deflationary pressure, I think helping on the pricing side for you guys relative to your customers. I imagine labor is an increase. Are you seeing any other areas where you can kind of reduce cost that you can pass through to the customer other than local sand?
Labor has got some inflationary pressure, trucking has got inflationary pressure, sand, I think we're going over the precipice of starting to see some excess capacity in the market, because the northern mines are hitting on all cylinders and the local mine -- more supply is coming online. So I think sand will get more favorable. The biggest opportunity for us and our customers that we're chipping away at every day that's mutually beneficial is efficiency. So how can we get more pump time on the assets and the customers benefit by that by reducing their spread costs and getting their production online faster and we benefit as a time and material billing business. So that's really been our emphasis.
[Operator Instructions] Our next question is coming from Connor Lynagh of Morgan Stanley.
If we could just stay with the sand sourcing for a minute. So I was interested to hear that you are almost 100% local in the Permian. Have you seen that yet start to translate to price breaks elsewhere as the Northern White mines see lower utilization or has that not impacted anything yet?
Yes, I think we're just starting to see it. Just like our business has some seasonality in the first and the fourth quarter, so does the sand business. So I think those mines are hitting on all cylinders and their production rates are up. And at the same time, we've seen a lot more -- I don't know what the tonnage number is in the Permian that we're up to, but it's substantial compared to where we were in January. So the combination of local mines coming online, Northern mines hitting on all cylinders, it certainly seems to be putting some excess supply in the market just over the last few weeks. So I'm optimistic, the last kind of year has been a grind on sand availability and pricing and transitory issues. And I think we're just starting to see some light on some deflation opportunities.
Got you. If we could turn to the other basins. So obviously, we've talked about the Permian and the Marcellus, have you seen any indications of upticks in demand in the Bakken and Eagle Ford, I think, you've alluded to this in the prepared remarks, but if you can expand on that a little bit?
Yes, I mean, we are seeing some increases in the Bakken. We have a couple of customers there that we work with are increasing as they go through the year. They've changed the current oil price level and the takeaway up there is going to cut the differential there. So it's quite a lot more economic than it's been in the past. And the Eagle Ford, we've got some activity in the Eagle Ford and we're seeing some upticks in that. And if people can -- it provides a way, I think, if they can move some capital to the Eagle Ford or the Bakken, if this takeaway thing materializes in some form or fashion.
How would that look for you guys, if you were to look to relocate capacity elsewhere?
Well, I don't think our customers are going to slow down. I mean, James mentioned that, we work for -- you guys know the customer base we work for. Its majors and larger independents and they feel good about their secured pipe. We do have the ability to move fleets very quickly. We got a national footprint, we've done it. But I don't anticipate from our customer discussions, we'll move it, but should there be some overcapacity in the Permian from some other operators that free up some frac, to the extent capital is reallocated to other basins would be constructive, or if we had some additional fleets in the future.
Our next question is coming from Scott Gruber of Citigroup.
James, I wanted to ask one question on the fire on the fleet during the quarter. Can you just provide some color on what actions have been taken to mitigate the risk of fire on other fleets, in particularly the legacy Trican pumps working down in Texas?
Yes, I mean, that's an ongoing risk, especially in summertime in the Permian. But we had already taken a lot of actions and we continue to take actions and try to put some protection around different hydraulic hoses, fire suppression -- more fire suppression on-site. All those kinds of things. I mean, we have an ongoing long list of that, training of our personnel, how to handle that situation, which they handled in an exemplary fashion on that particular one. So that's kind of a long list of things. There's not one kind of cure-all for that because it gets so many different pieces of equipment out there.
Yes, Scott, I just want to clarify there is nothing that we disclosed that we found in investigations that points to any type of equipment that Keane runs. So this is a risk that's prevalent in the industry. We take it very seriously on training and mitigation. And we've a lot of big root-cause investigation, a series of projects going on in the further mitigation. But there is nothing that points to a specific piece of equipment or any risk profile on the company.
Got it. Just wanted to clarify that. And another point of clarification, which I think will be good for all the listeners. You were talking about the Marcellus previously, there is lot of market rumblings about pricing in Northeast during the quarter. Greg you mentioned that pricing in the book was rock-solid. So just to clarify on that point, does that mean that based on what you know today and obviously things can change, but based on what you know today, does that mean that there is basically no risk to pricing rolling lower on dedicated agreement to North East and they have a limited impact on 3Q, but may reveal itself in 4Q?
Yes, I mean, the pricing isn't really basin specific because these assets are so mobile, so there is temporary dislocation from time to time, but it sorts itself out. But I would say the risk and opportunities in all of these basins are different. In the Permian, there is the takeaway, in the Marcellus, they don't have the same benefit of the WTI, right? So if budgets were to exhaust, there could be some overcapacity. Where with see things today, we're maintaining utilization and our profitability. So we don't see a ton of risk on the horizon in the near term. But there's -- it's a dynamic business and all the customers are making their own economic decisions. So we always keep an eye on those things.
So just based upon kind of what's in the agreements in the Northeast today, I'm assuming no seasonality, just things kind of progress as they are, kind of roll forward into 4Q will the profitability on the Marcellus/Utica book basically be the same 4Q on 3Q?
Yes, that's the same across the whole company.
Our next question is coming from Vaib Vaishnav of Cowen & Company.
Just wanted to speak about RSI deal. If you could provide some color, life of the assets left; any color on how those assets were maintained? You spoke about they were well-maintained. But just like, how much life left? Are they working or is this a new incremental fleet that you're talking about?
Yes, so thanks for asking. So RSI is a high quality chemical company that over the years had gotten into frac business. And at this point, viewed it as non-core and thought it would be a better home with a bigger frac company. So that's how we sourced the deal. The assets were working in the North Eagle Ford out of a base in Bryan, Texas and then they had a couple of pump-down crews scattered down in South and West Texas. I would say the utilization rate was fairly low. They were kind of working between different spot customers. So this is a consolidation play. The assets were working. The assets are kind of 4 to 5 years old, so there's plenty useful life left on them. We inspected them like we do on all due diligence. They kept their components fresh. So for us, this is an asset deal. We're not picking up that work in North Eagle Ford. we're moving the assets for the 3 pieces we described. Some to replace the damaged assets, some to go into the maintenance rotation, and ultimately 1 incremental feet. We'll get those fleets harmonized with Keane, which we're working on now. We just closed the deal last week. So we're moving them and branding them and harmonizing some of the operating systems and then they'll be deployed.
Switching to electric fleets. Just want to get your thoughts on how you view electric fleet? How viable that technology is? And your thoughts on the market?
Yes, so we study all types of different surface technology. I think electric fleets are interesting, but from a return profile, it's much higher entry point. So I don't think it's something we are actively chasing. I think we will keep an eye on it. There's pockets of it. I think it'll be a niche application that's contingent upon the savings, the arbitrage between oil and gas. And we've studied it, we'll keep an eye on it, but we don't necessarily see it as a return profile as something we're going to go after aggressively and be a first mover on.
Got it. And one last question for me. Just on CapEx. Any change from -- in CapEx from either the fleet that's burned or from RSI fleets?
No, the CapEx plan is the same, as we communicated back in January. It's on track. Maintenance CapEx is on track. And the growth that overlays that for the 3 new fleets, so everything is on plan. One other interesting point on the RSI deal at $35 million, $34.6 million, it's about 400-horsepower. We mentioned we have insurance coverage at replacement and expect procedures in the quarter that will be roughly 50% of the purchase price. So we expect to recover from insurance proceeds. The accounting will be a little bit different on -- it will go through the income statement in other income. But on a cash basis, it kind of dilutes that purchase price from 400-horsepower almost to 200. So it increases the value on that deal.
[Operator Instructions] Our next question is coming from Michael LaMotte of Guggenheim.
Greg, if I could clarify the guidance quickly, with fleet 28 starting in July. You talked about 27 for the quarter. Is that really just being conservative or is there some cushion there on the efficiency? And I'm really asking more from the perspective of the customer and the urgency. Have you noticed any sort of letting up in urgency that might impact your efficiency?
Yes, I mean, the difference between the 27 and 28 is merely our ability to get the damaged fleet back to work. On the 27, we're not seeing any change in urgency or efficiency. Second quarter was an off-the-charts quarter for us as far as efficiency. We -- on an annual stages, we've said 1,400 stages per fleet is the number we have been running. We felt that was pretty good efficiency. In the second quarter it was north of 1,500. So second quarter was strong. Second quarter and third quarter are usually the wheelhouse where you don't have seasonality. But there is nothing in that guidance as efficiency fall-off or white space. There is just 1 fleet until we get that other fleet back on its feet.
Great. Then CBR payments to RockPile, are they cleaned up now?
Everything is cleaned up now. It went through the income statement in the first quarter, at the end of the first quarter and the cash went out in early April. So it was a cash event in the second quarter and an income event in the first quarter and it's all cleaned up.
Okay, great. And then, James, I know you can't get too specific on the strategic priorities, but if you could maybe provide some rough color as to what your priorities are going to be now, in your new role?
Yes, it's a good question, Mike. Thanks for asking that. But it's going to allow us -- we have a chance to bring in Robert, who is a well-known Senior Manager in this business and as we have grown the company and have a chance to bolster management, we've continued to do that. So it allow me to be a lot more strategic and we continue to indicate that we are big believers in consolidation and bigger consolidation. So hopefully that can help us move that forward and execute on some of that faster.
The M&A and technology, is that something that you're going to be focused on?
Technology is a big one too. I mean, we've got projects running on surface technology, down-hole fluid technology, cementing technology, all of those things. A lot of stuff in the works on that as we continue to grow.
And Michael, we're not going to let him out of his sales role.
Our next question is coming from Daniel Boyd of BMO Capital Markets.
Greg, just wanted to follow up on the CapEx question. Can you just maybe give us some thoughts around where the run-rate is for maintenance CapEx? And particularly, as we kind of think about 2019, if we try to book end it with 2 scenarios, and sort of one, where the market stays as strong as it is today and as you expect it to continue; and the other in a scenario where all of your fleets continue to work so maybe pricing isn't as attractive to incent new-builds. So where can be go on a low-end next year if we were just at a maintenance level, but everything is working?
Yes, so the fleets are -- the maintenance CapEx is kind of agnostic to price. The fleets work and the hours run up and the components have to be replaced. So we've been pretty locked in at 4 million a fleet per year for almost 2 years now. We dialed that number in and we feel good about that. We got some run year fleet simulators to run out the service intensity and predict when we need components and that's how we do our supply chain planning for components. So the 4 million per fleet is a variable number. So it's not driven by price, it's driven by activity. So however many fleets are working, times 4 million is your maintenance CapEx number and then any growth projects just layer on top of that. But there is no growth projects in the queue as we sit here today. So 29 fleets times 4 assuming full utilization is your baseline and you can do sensitivities off of that.
Okay, great. So very strong cash flow if we had draconian pricing come in?
Correct.
And then just one on pricing, I know you have all your dedicated fleets, can you just remind us on when you have price openers in those? And have you had any price discussions over the past, let's call it, 45 days, when people really talked about the weakness where that gives you confidence that your dedicated fleets will maintain strong pricing?
Yes, so the pricing, most of them are quarterly reopeners and they are on a rolling basis, not fiscal. And the only data point I can give you is, you saw our profitability we delivered in the second quarter and what we guided in the third. So that leads to relative insulation on those pricing discussions. As James mentioned in his remarks, so far we see the business is very constructive. Our customer relationships is very sticky. They like the service we are delivering and the efficiency. And as a result, we have not really seen any cracks in that today.
At this time, I would like to turn the floor back over to Mr. Stewart for closing comments.
Thank you. And thank you, once again for joining us on our call this morning. We're pleased with our results for the second quarter, and remain confident in the future of our business and look forward to updating you again soon. Have a great day.
Ladies and gentlemen, thank you for your participation. This concludes today's conference, you may disconnect your lines at this time, and have a wonderful day.