FTS International, Inc. (NYSE:FTSI) Q2 2019 Results Earnings Conference Call July 31, 2019 10:00 AM ET
Mike Doss - CEO
Lance Turner - CFO
Conference Call Participants
John Daniel - Simmons Energy
Taylor Wleczyk - Tudor, Pickering, Holt
Harry Collins - Bank of America/Merrill Lynch
Andrew Ginsburg - R.W. Pressprich
Stan Manoukian - Independent Credit Research
Thank you and good morning, everyone. We appreciate you joining us for the FTS International Conference Call and Webcast to review Second Quarter 2019 Results. As a reminder, this conference is being recorded for replay purposes.
Before we begin, I would like to remind everyone that comments made on today's call that include management's plans, intentions, beliefs, expectations, anticipations or predictions for the future are forward looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.
These forward looking statements are subject to risks and uncertainties that could cause the Company's actual results to differ materially from those expressed in any forward looking statements. These risks and uncertainties are discussed in the Company's annual report on Form 10-K and in other reports the company filed with the SEC. Except as required by law, the Company does not undertake any obligation to publicly update or revise any forward looking statements. The Company's SEC filings may be obtained by contacting the Company and are available on the Company's website, ftsi.com and on the SEC's website SEC.gov.
This conference call also includes discussions of non-GAAP financial measures. Our earnings release includes further information about these non-GAAP financial measures, as well as reconciliations of these non-GAAP measures to their most directly comparable GAAP measure.
I'll now turn the call over to Mike Doss, FTSI's CEO. Mike?
Thank you, and good morning, everyone.
I'm here with Lance Turner, Company's CFO. I'll first go through our financial highlights and then I'll cover some business and technology updates, before going to Q&A.
I'm pleased to announce that we had another strong quarter operationally as our crews continue to increase their pumping hours in stages per day. Revenue was $225.8 million in the second quarter, up 1.5% from the first quarter. Our stage count increased by 7%, but the revenue impact of that was mostly offset by lower sand revenue, as more customers source their own sand and lower average pricing.
We had 21 average active fleets in the second quarter, up from 20 in the first quarter. Today we have 20 fleets working with nine in the Delaware Basin, one in the Midland Basin, three in South Texas, three in the Northeast, three in Mid-Con and one in East Texas/TMF.
Of the 20 fleets, 10 are working for a large cap E&Ps, three are working for small and mid-cap E&Ps and seven are working for private E&Ps. Three locations are single well, ups and the rest are zippers.
Adjusted EBITDA was $41.9 million, up from $39.4 million in the first quarter on the higher volume, offset by a full quarter impact of pricing concessions that we gave in the first quarter.
Excluding a loss from our wireline business which was idled at the end of June, adjusted EBITDA in the second quarter would have been $43.8 million or $8.3 million per fleet annualized. SG&A was $21.7 million in the second quarter, down from $23.6 million in the first quarter. SG&A for the third quarter is expected to be between $21 million and $22 million. Net income was $5.9 million or $0.05 per share in the second quarter compared to a net loss of $55 million in the first quarter.
The loss in the first quarter was primarily due to $60.8 million of charges related to supply commitments and asset impairments. As for guidance, we expect to average between 19 and 20 average fleets in the third quarter with adjusted EBITDA per fleet of $7 million to $8 million. The slight guide down on EBITDA upper fleet is due to us expecting to lose a few points on pricing. We currently expect to exit the third quarter with 17 or 18 active fleets due to customers dropping fleets. We're going to try to place those fleets, but we won't work for free. Our cut off is about $5 million adjusted EBITDA per fleet.
CapEx was $14.9 million in the second quarter, up from $11.7 million in the first quarter. We currently expect to spend between $55 million and $60 million for the full year. Our annual maintenance CapEx requirements are between $2.5 million and $2.7 million per active fleet, which is one of the best - one of the lowest in the industry. That is due to our structural cost advantage in manufacturing and modular pumps, which are perfectly designed to handle today's high intensity work and increased pumping hours.
Our cash flow in the second quarter was impacted by a $15.9 million payment related to previously accrued supply commitment charges. Additional amounts were paid as partial year reservation fees included in prepaid assets. That's it for this year. Next year, the settlement payment will be $11 million and occur in the first quarter, along with reservation fees for the full year. All five remaining annual settlement payments are fully accrued for.
We ended the second quarter of $162.1 million in cash and net debt of $313.8 million. In the third quarter, we expect to close on the sale of our 45% interest in SinoFTS our joint venture in China, to Sinopec for total proceeds of 33 million.
As mentioned in our release, we are on track to generate approximately $100 million of cash flow in 2019. It could be slightly higher than that including assets proceeds. As for share repurchases, we bought back approximately 761,000 shares for $4.6 million in the second quarter. We plan to continue to purchase small amounts opportunistically.
Shifting gears, as I mentioned at the outset, we had a good quarter operationally. We completed 344 stages per fleet, our second highest quarter ever, which is especially remarkable considering the average stage times have increased by 16% since the second quarter of 2017 when we achieved a record 356 stages per fleet. Note this stages per fleet are not necessarily comparable between companies. There are differences depending on geographic footprint, stage times, treating pressure and the amount of zipper versus single well ops.
Despite the strong operational performance, the environment is challenging commercially, given the oversupply. Contributing to that our E&Ps especially publicly traded E&Ps, reducing fleets due to pressure to live within cash flow and to not exceed previously announced CapEx budgets. Higher completion efficiencies industry-wide are also a factor.
For fleets that are released, opportunities in the spot market are few and far between and competitively bid. We've recently lost bids to competitors at prices 10% to 15% below us, and I believe we already offer an attractive value proposition to customers.
Next, I'd like to highlight a few of our technology projects. As a manufacturer, we believe our platform allows us to implement improvements much faster than if we relied on third parties. That said, we do closely follow new technologies available on the market.
One focus area remains our fluid ends. About 25% of our R&M expense relates to fluid ends and fluid ends failures are a common cause of NPT. Over the past few years, we have made a number of changes to our fluid ends from changing the geometry to allow for more efficient flow to improve metallurgy.
We've also employed the use of sleeve technology. These improvements and others have reduced our fluid end expense per pumping hour by 25% over the last two years, while our average trading pressure has increased by about 15% over the same period.
We have another project underway to improve the durability of our blenders. Most blenders were not built for today's intense jobs, along with operating for significantly more hours per day, per month and per year. We are deconstructing our blenders to pinpoint and fortify weak points with the goal of reducing the frequency of blender related NPT events.
Upgraded missiles, which we designed and built, are reducing the risks of capitation in our pumps, which has improved useful life. This is another example of how we've used the vibration sensor data to redesign equipment to reduce damage accumulation.
We continue to make strides towards automation. We are now at the point where our software notifies the operator of equipment at risk of failure along with recommended actions. By the end of the year on at least one fleet, the software will automatically take action unless the operator declines, which is expected to both reduce NPT and improve the quality of stages completed.
We have a project engineering team as part of our national operations center in Alito that is involved in all of these projects and many other ancillary projects such as the use of diverting skids and restoring a real time fluid control system.
Lastly, let me share a thoughts on electric fleets. At a cost of $50 million to $60 million, the economics simply don't work in this environment. We also think that we are in the early innings and the best design has not yet been discovered. However, we are watching developments closely.
For the customer, the benefits are twofold. Fuel savings and lower emissions. All of our customers would like to save money on fuel costs, which runs about $1 million per month per fleet on diesel. An alternative to electric fleets are dual fuel fleets, which also provide the flexibility to continue to operate if natural gas becomes unavailable. We can retrofit one of our Tier 2 fleets at a cost of about $2 million to burn gas with about a 50% diesel displacement rate on average.
We currently have three such fleets. [Indiscernible] DGB or Dynamic Gas Blending engines are specifically designed to operate as dual fuel and are advertised as having a higher diesel displacement rate of about 75% on average, making them particularly appealing. We are currently evaluating whether upgrading one or more of our existing fleets with these new engines makes sense commercially and economically.
Before we go to Q&A, I'd like to recognize the contributions of our hard working employees. We have some of the best people in the industry, and they have shown true dedication to service quality and incredible perseverance in dealing with the cyclicality of our business. So to those listening, thank you for a job well done.
I'll now turn it over to the operator for Q&A.
[Operator Instructions] And our first question comes from the line of John Daniel with Simmons Energy. Please go ahead.
Quick question for you on the - and I probably have the background noise, I am on the airport. When you guys talk about the fleet count dropping to maybe 17, 18 fleets at the end of Q3 are you and I know it's early, but I mean, at this point. Firstly are those fleets been - are you losing them because someone underbid you or that's just the customer who is shutting down work. And then if you could look at your crystal ball, just kind of give us your thoughts as to what that count might happen - what might happen as you're going through Q4 into the holiday season?
Sure well, there is a lot of uncertainty, the further out you go, but as far as the third quarter, the fleets being dropped are due to customers just cutting back on activity. We did lose one fleet in a bit of a price war with a competitor. And as far as the fourth quarter, we think we're going to see some budget exhaustion, which we typically see in November, December, and no reason I think that we won't see that this year. But we don't really have a good estimate.
Okay. And - when you look at the stage count, which is really impressive I mean, the customers are dropping weight not because of performance or the spec, but it’s because of budgetary reasons. So assuming that's right. Are they also telling you hey, Mike, Lance, we're going to be coming back in the first quarter, like is there an expectation like last year - most rates will be returning, as budget dollars or refreshed or is it purely?
Yes, no, absolutely. And so a lot of it is just companies are being very strict about capital discipline and staying within budgets. And so, to the extent that they're ahead of plan, which many customers are, that's going to lead to some softness in the fourth quarter. And then everything gets reset January 1 and as far as your comment earlier on releasing the fleets, it's due to budget constraints almost entirely.
And I guess the final one from me and I don't know how specific you can get on this, but like, we all know that - more and more consolidation is needed at your sector. Can you just give us your latest thoughts on where you see that and how you might playing that?
Sure, yes, absolutely now we've, I think we've commented on this before, position hasn't changed. We think consolidation makes a lot of sense in this industry. It provides a larger platform across which to allocate your costs and those are some clear benefits associated with that. Also, if you get the right combination, you could get some diversification in terms of customer base, which could be another additive benefit, but we expect to see more of it,
And we are interested, we're not - under pressure to do any deals, but I think we're open-minded in what we consider the right opportunities for sure.
Our next question comes from the line of Taylor Wleczyk with Tudor, Pickering, Holt. Please proceed with your question.
I wanted to start by just asking on the two to three fleets that are coming down or likely to come down here in Q3. What basins and plays are those two to three fleets in specifically and then I think on the last call you called out a handful of fleets that were underperforming, the average annualized EBITDA per fleet. I think somewhere around $5 million with those three fleets fall into that bucket?
No, not necessarily, they're really not related. I think the fleet's being dropped, a couple of them in the Northeast that's probably our weakest area at the moment. And then, one or two in West Texas, but we're finding replacement work for some of those. So mostly in the Northeast for two of them and then the others which would be offset by some wins would be of activity in West Texas. And what was the other question that you had about the 5 million?
I was just asking. Last quarter, you basically called out two to three fleets that were right around, the price were at around $5 million of annualized EBITDA per fleet and I was curious that those three fleets fell into that bucket.
Oh no, they didn't. And of those fleets that I've mentioned on the last call we were ever able to remediate a couple of them just through high grading or contract renegotiations. And so, we had some success with that, but I could say the overall market still remains pretty weak.
And then when you talk about $100 million of cash flow for 2019, could you just refresh for us what definition you're using there? And then does that include the proceeds from the JV sale - the minority interest in your JV that are coming in Q3?
Sure yeah, our free cash flow definition is basically cash flow from operating activities minus capital expenditures. And I think the asset sale proceeds, which will be larger this year because of the joint venture disposition, are going to add to it. So, we could be a bit over $100 million on our scenarios, including asset sale proceeds.
[Operator Instructions] Our next question comes from the line of Harry Collins with Bank of America/Merrill Lynch. Please proceed with your question.
For the pricing commentary regarding the 7 million to 8 million in EBITDA per fleet next quarter. What's kind of driving the pricing down and do you think 3Q will be the bottom for pricing, what do you think another write-down 4Q?
It's a little uncertain at this point. I'd say we're not at a price war territory yet as an industry, but I think just given the expectations of a softer second half there have been some concessions that have been given. Hard to say if it's the bottom and I don't think that the price decreases will be material on average and nothing like what we saw in the first quarter with our customer base.
And so does this imply that the - two to three fleet if you to drop in or stacking in 3Q are priced higher than rest of the fleet?
No, not necessarily. When I go through the three fleets, I think you've got a broad mix you've got some that we're on the lower end of the spectrum. And I think you've got one that was kind of in the middle, upper, middle pack. So, I'd say that they're probably average.
And then a couple of competitors have talked about the zipper fracs mix shifting to more single well pad in the back half and that is impacting efficiencies. Are you guys seeing this, you mentioned towards the end of the call the mix, but you guys see a shift and then the back half is kind of slowdown?
No, nothing seasonally, that's anything noteworthy, you know customers, they kind of vary at any point time, we could have more or less zipper operations of course, we prefer zipper operations. It does tend to be done a little bit a lower price, other things being equal, but not really seeing a shift from what we're seeing.
And then did you guys give a zipper frac mix beginning of the call in 2Q, about your kind of percentage was?
We did not, but it's about 70% this quarter and so, that's up from last year.
Our next question comes from the line of Andrew Ginsburg with R.W. Pressprich. Please proceed with your question.
I just wanted to follow-up on the $100 million cash flow comment. So it looks like if we basically annualized first half, it would get us to about $50 million free cash flow, and since we're seeing the Sinopec divestiture isn't included in that $100 million cash flow guidance. Just trying to reconcile the disconnect from a softer second half, but on an annualized basis to the first half coming at $50 million. Can you provide - some commentary around that?
Yes, so the first half the $50 million you mentioned, I would expect in this excluding the channel JV proceeds. The second half would be a little softer just because if you think about the cash conversion in the first half, it included Q4 of last year and our EBITDA numbers have stabilized but have come down a little bit since Q1. And then you add on the China JV, it should be over - well over a $100 million.
And so that's kind of how I think about the cash flow. Obviously there's a lot of variables there on fleets and working capital that we try to model out, but that's in general the way it's going to happen. And then the other thing on the annualizing is the [Cobia] payment. Obviously, the timing of that is impactful from a cash flow perspective if you're including working capital.
And that was the $15 million or so that you mentioned earlier on the Cobia payment.
Okay. And then just to follow I’ll ask one more question, do you think - how are you guys looking at the equity buyback? So we have utilization dropping more and more because things are getting pretty competitive. So in terms of the equity buybacks, are we really looking to drive forward with that or depending on utilization and casual metrics for the year, maybe pull back on that if you could just provide some commentary on that as well.
Yes, so yes, we executed a pretty small amount in Q2 and so I don't expect to ramp that up significantly. The way we look at it is we're going to be looking at the outlook. We're going to be balancing our liquidity. The equity buyback is one avenue. We've also got the term loan, which we've brought down significantly and we'll continue to consider that.
And then in the past, we've also kind of utilized notes, repurchasing notes in the open market. So we'll look at all the options, balance our liquidity, bump that up against outlook. And you know, ultimately we're focused on returns and cash generation and then we'll kind of choose the best allocation for that.
[Operator Instructions] Our next question comes from the line of Stan Manoukian with Independent Credit Research. Please proceed with your question.
In regards to the capital allocation that you just mentioned, capital allocation decision - the best return on cap - on capital between buying back the bond sale in - the term loan or buying the stock, I was wondering how does this decision relate to the utilization of your feet and is it sort of related to the - your future outlook on what's going on in the market or do you have different variables to sort of make up your mind on how to allocate your capital?
Yes, so I'll - Stan I'll try to answer that question. So in terms of capital allocation, I mean, I think we're pretty flexible in how we do that. So it does definitely take into account some of our views on the business outlook despite all the uncertainties we have an outlook that we execute against and so, I mean, I think we're going to be prudent with the softer market that we're in.
I think, as Lance mentioned, that we're going to basically continue to just nibble at the share repurchases. That's not going to be a large share, at least at this point and then as far as the other capital allocation decisions on debt repayment versus liquidity levels, we just continually assess that. We want to make sure that we have sufficient liquidity to handle all scenarios.
And to follow on this, if I may. What sort of fuels your confidence that this slowdown is just a cyclical sort of downturn versus sort of permanent trend. There is a lot of noise in the market that fracking industries are in trouble and there's going to be more bit of allocation of capital by trailing companies, by your customers towards maybe offshore or some other sort of sources of oil drilling. And but you're still confident that you have the highest percentage allocations on the spot market. So the question is, number one about your fuels of your confidence. And second, where do you see more softness in the spot market. Or, you know, in the market with large oil companies?
Yes, So I'll try to answer some of that and if I leave out a piece, just let me know. But as far as, you know, what’s the weakest segment of the market, I mean, for sure, the spot market is the weakest. And that's always an indicator of the overall strength of the markets.
If the spot market is above the average pricing and the strong market of its below it's weak. And so we're definitely in that position at this point. Dedicated pricing definitely tends to converge to spot, but I think there's a time element there. And also customer base can have an impact on that as well.
And so that's the sense of the market is, I think, ahead. I don't I don't think the shale industry is condemned by any means. I think it's been incredibly productive for the economy. And yeah, I think we've just sort of been victims of our own success to some extent.
And we continue to get more and more efficient, getting more wells, more lateral fleet with drilling rigs. Completion crews are doing their work more efficiently than they ever have. And so you just need less equipment to maintain a certain level of production.
So I think that we're going through a transitional period where maybe the industry was built for 200 rigs, but 900 is really all it takes. And so don't see a lot of material downside risk to the rig count. I mean, it could slide a bit lower as efficiency and capital discipline are definitely topics of the day. But I don't see a scenario like 2016 where just a bottom drops out and commodity prices was really the main driver back then today it's much more of the capital discipline theme and efficiencies.
And so those are just kind of my quick thoughts on it. I think another thing that could lead to improvements in the supply and demand of frac horsepower is just the rate of attrition. So, as activity has come down, fleets have been drops. They're kept warm for a certain amount of time. But eventually they kind of drop out of the marketed bucket.
And so when we see variations in activity like the increase that we currently expect to see in the first quarter resumption of spending, the market will tighten up and will tighten up enough that we have pricing power. It's too early to say. But at some point, we expect that will happen. Just kind of given the natural attrition cycle and what happens in response to two weaker periods like the one we're going through now.
Now, that's very much appreciated. Just one quick comment if I may. It is not a secret as far as I know, that the main part of the competition pricing were - is related to the integrated [indiscernible] oil companies that have sort of pressing problems, but if they get revenues from other sources and the question is, do you expect the accretion to derive from them or from sort of from independent frackers?
You know, it's hard to know. I mean, the majors, the integrated oils have come back onshore the last couple of years, you know, I think that they're going to face the same economics as the independents, the same pressures to generate returns and cash flow on their investments.
I don't think the wells that the majors are drilling are magical in any way. And so I think they're going to experience some of the same impacts that that the independents are facing. But there's no doubt this year that the majors are up pretty significantly and they're spending onshore, whereas the independents tend to be down by single-digits, 10% maybe. And so while you're seeing that shift. But I don't think that will continue. Those kind of growth rates are going to continue for a further integrated. That's just my expectation.
Our next question is a follow up question from the line of Harry Collins with Bank of America/Merrill Lynch. Please proceed with your question.
For the two to three fleets dropped in 3Q, are those spots are dedicated fleets. And are they - what kind of customer are they as far as likes mid-cap, large cap major.
Let me think for a minute. Two of them are privates, one is independents. And I think we may lose one or two others and gain two or three others, that that's where the uncertainty comes in terms of the exact count. But I think that activity turnover is just in the public E&Ps. And I mentioned the two that are dropping off that are privates. Yeah, go ahead Lance.
I think one would have been dedicated, right. One was dedicated and the others were operating on a spot basis, more or less.
And whether that land you guys kind of on a spot to dedicated mix? Pro forma I guess.
Probably around the 60% mark.60 dedicated.
Now we are showing no further questions at this time. I'll turn the conference back over to you.
All right, well, thanks again, everyone, for joining us today and we look forward to updating you next quarter.
Ladies and gentlemen, this does conclude today's conference call. We thank you for your participation and ask that you kindly disconnect your lines.