哈里伯頓 (HAL) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halliburton Second Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, today's conference call is being recorded.

I would now like to turn the conference over to Lance Loeffler. Please go ahead.

Good morning, and welcome to the Halliburton Second Quarter 2017 Conference Call. Today's call is being webcast, and a replay will be available on Halliburton's website for 7 days. Joining me this morning are Dave Lesar, Executive Chairman; Jeff Miller, President and CEO; and Chris Weber, CFO. Before we begin, I would like to point out that this will be Dave's last time to participate on our earnings call, given his new role as Executive Chairman.

As a reminder, some of our comments today may include forward-looking statements reflecting Halliburton'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. These risks are discussed in Halliburton's Form 10-K for the year ended December 31, 2016, Form 10-Q for the quarter ended March 31, 2017, recent current reports on Form 8-K and other Securities and Exchange Commission filings. We undertake no obligation to revise or update publicly any forward-looking statements for any reason.

Our comments today also include non-GAAP financial measures. And unless otherwise noted, in our discussion today, we will be excluding the impact of the early extinguishment of debt and charges related to an interest-bearing promissory note that Halliburton intends to execute with its primary customer in Venezuela. Additional details and reconciliation to the most directly comparable GAAP financial measures are included in our second quarter press release, which can be found on our website.

(Operator Instructions) Now I'll turn the call over to Dave.

Thank you, Lance, and good morning to everyone. Our performance this quarter demonstrates that Halliburton is the execution company, and we are the leader in North America. Here are a few key highlights. Total North America revenue increased 24%, outpacing the average sequential U.S. land rig count growth of 21%. North America margins grew into the double digits. And although our international operations continue to be challenged, the numbers came in about as expected, and we continued to tailor our business to the market as we wait for a recovery. And we outperformed our major peer in every single geo market, demonstrating once again that we continue to grow our market share globally.

Since this is my last call, today I want to share with you my view of the evolution of the North America land market, our customer base there and why I believe it will continue to surprise to the upside. Now for 25 years, I've had a fantastic front row seat to the development of U.S. unconventional resources. We have become the largest service company in North America, and that growth didn't happen by accident. First, it was due to the leadership of Jim Brown and his visionary management team. They saw the potential of unconventional resources in the region at the same time as a group of key early mover customers. As a result, we decided to work together using lots of trial and error to unlock this resource. We established enduring customer relationships and gained unparalleled basin knowledge that still provides us a sustained advantage today.

I think it's important to look at the North America unconventional ecosystem to understand our customers' behavior and why their ability to so quickly increase production has expanded rapidly. Currently, there's a strongly held view by energy investors that the U.S. independent operators behave as a group. That view is wrong. When thousands of companies make discrete decisions about the same market each day, they do have a tendency to swing the activity and production pendulum too far one way or the other. That is not groupthink. It's the impact of individuals trying to do the right thing for their investors.

Our U.S. customer base is not 10-or-so countries like OPEC. It is made up of thousands of companies from IOCs to individually owned businesses. When you look at them separately, you see thousands of entrepreneurial, smart and motivated risk takers. They readily adapt to the quality of their reservoirs, have almost unlimited access to capital, aggressively apply new technology and quickly mark their business models and structures to meet changing market conditions and yes, sometimes even take advantage of U.S. restructuring laws. They are your classic American entrepreneurs, and their success should be recognized.

In Silicon Valley, such a success would be greatly celebrated as another industry disruptor. The unconventional disruption is not widely celebrated beyond the energy space, but it should be. The development of U.S. unconventional resources has been as disruptive to the global energy markets as Amazon has been to big-box retailing or Uber to the taxi business. It unleashed a wave of cheap, reliable energy that has disrupted global geopolitical and energy dynamics, made the U.S. more energy independent, caused OPEC to react and changed the fundamental economics of offshore production. And I believe it has created hundreds of billions of dollars of economic value, added hundreds of millions of dollars to government tax coffers and provided untold savings for consumers. So unconventionals is what I would call a disruptor, so let's celebrate that.

Now I've heard energy investors say that today's customer behavior shows nothing was learned in the last downturn. That simply is not true. Our customers are smart and adaptive, and they do learn from the past. Their business DNA is to be survivors, and they are. Look at their reaction in the past several weeks. Today, rig count growth is showing signs of plateauing, and customers are tapping the brakes. This demonstrates that individual companies are making rational decisions in the best interest of their shareholders. This tapping of the brakes is happening all over the place in North America. I can tell you the market will respond. It will rebalance, and these companies will stay alive, survive and thrive because that is what they do.

I said several quarters ago that customer animal spirits were back, and they are with a vengeance, and they are now running free through North America. Here is my last piece of wisdom for you. Do not bet against the animal spirits that our North America customers embody. I never have and I never will because that is a bet that you will lose.

Now today is my last conference call, and I'd like to take a moment to thank our analysts and investors. It's been a pleasure working with you. And although we haven't always agreed, I've always enjoyed the spirited debates and intelligent conversations.

I would also like to thank the employees at Halliburton for their hard work throughout my career. We have been through many cycles, emerging stronger from each one, and I am proud of what we have accomplished together.

And even though I will be absent from future calls, I look forward to the next 18 months, serving Halliburton as Executive Chairman. I am happy to leave these calls in the capable hands of Jeff, Chris and the other members of our experienced management team. I have no doubt they will continue to lead the company as a customer-centric and returns-focused business. And remember one thing: We are the execution company.

With that, I'll turn the call over to Jeff.

Well, thanks, Dave, and good morning, everyone. I'm pleased with our second quarter results. We continue to execute our strategy to maximize asset value for our customers and deliver differentiated technology and services that we believe will generate superior returns over the long term.

Here are some highlights for the second quarter. Total company revenue was $5 billion, representing a 16% increase compared to the first quarter this year. Total adjusted operating income was $408 million, primarily driven by continued strengthening of market conditions in North America, which were partially offset by pricing pressure internationally. Our North America revenue increased by 24%, outperforming the average sequential U.S. land rig count growth of 21%.

The Completion and Production division revenue increased 20%, and operating margins improved by an impressive 700 basis points to approximately 13%, driven by the strength of our production enhancement, cementing and completion tools product service lines. Cash flow from operations delivered about $350 million.

And I'd like to take a moment now to welcome Summit ESP and its employees to the Halliburton family. We are pleased to announce this recent transaction and are excited about what it means for us as we continue to strengthen our Artificial Lift capabilities.

Now I'd like to provide some regional commentary around our quarterly performance. I believe we've found the bottom of the international rig count in the first quarter. However, I don't expect a near-term rebound in the international markets for several reasons: first, the lengthy contracting cycles will mute any near-term pricing inflection; second, our international customers need confidence in commodity prices in order to overcome the duration risk in their projects. We continue to collaborate with our customers to lower the cost on these projects. And while some are moving towards FID, it's important to remember that there's a significant time between planning FID and revenue generation for Halliburton. And finally, I've been consistently more conservative on the international market, and it's played out exactly how I called it. Today, I expect that there will be improvement in activity over the remainder of the year, but these improvements are not concentrated enough to offset the continued pricing pressure. As a result, international markets will continue to move sideways.

With all of this said, it's important to understand that we are now into the third sequential year of significant underspending in the international markets. This implies that the production declines outside of certain OPEC countries will begin to accelerate, particularly next year, as the backlog of new projects are completed and additional projects are not coming behind them. In the meantime, we are actively managing cost while protecting our valuable international position for the eventual market recovery. With the current level of underinvestment internationally, production declines are a certainty, and you know where that leads.

Our Drilling and Evaluation division is driven in large part by our international footprint. And while we experienced a modest increase this quarter, largely driven by increased drilling activity in Latin America and the seasonal rebound of North Sea and Russia, the overall market continues to move sideways with continued pricing pressure.

Now turning to North America. After the operational update we gave in the first quarter, some of you were skeptical when we accelerated our equipment reactivation. But based on our performance during the second quarter, there is no doubt we successfully executed our plan and that this decision was not only right but dead on target. Why is that? During the second quarter, we continued to see strong incremental demand for completion equipment from our customers. The reactivated equipment we brought back went to work at leading-edge pricing and has been accretive to overall margin and is expected to deliver acceptable returns that exceed our cost of capital. Our sand war room and logistics infrastructure allow us to manage the completions intensity our customers demand today, and we've been successful passing along supply cost increases to our customers.

Our internal manufacturing capability is a proven differentiator in today's environment. It allows us to be flexible while being able to build what we need when we need it, particularly in a rapidly changing market. But today, we believe the current customer demand has outpaced the supply of completions equipment, and this should create a runway for a strong utilization through the second half of the year. We remain committed to generating industry-leading returns, and reactivating our equipment was the first step towards delivering the results you have come to expect from us.

As some of you have heard me say before, customer urgency is the foundation for the path to normalized margins. Today, our customers remain urgent and therefore, we believe our path to normalized margins is achievable. We get there through a combination of increasing leading pricing, improved legacy pricing, better utilization and continued cost control. Let me be clear. Our pressure pumping equipment is sold out in the third quarter. As we gauge the utilization of our equipment on a 24/7 basis, we see a significant opportunity to improve and drive the downtime out of our calendar. In this environment, it's imperative to be aligned with the most efficient customers, where we can create value for them while delivering the best returns for Halliburton. Filling our calendar with hyper-efficient customers is an important part of what allows us to achieve our margin goal.

Looking forward, it's too early to tell the impact of commodity prices on customer plans for 2018. However, as Dave said earlier, at Halliburton, we never underestimate our customer's ability to adapt to the environment. In the first quarter, we experienced significant inflation in sand prices and increased volumes. As we continue to pass through sand cost to our customers, we expect to see greater technology adoption making better wells through engineered solutions. For the first time in years, in the second quarter, we experienced our first decline in average sand pumped per well. Let me repeat that because I think this is important. We saw a decline in the average sand pumped per well. And while this is only one data point, it's something we'll be watching. We believe current sand price levels have encouraged operators to optimize their completion design using more science as opposed to simply maximizing sand in a trade for increased production.

We maximize returns on our technology investment by being the most effective in the market at lowering our customers' cost per BOE. Our strategy around technology development is to make returns for Halliburton. Very simply, our decision process around technology can be summed up into 3 questions: first, does it reduce costs; second, does it produce more barrels; or third, does it do both? As a result, we create cutting-edge technology that sets new standards for service quality and performance while making better wells for our customers. For example, in a recent effort in the Permian Basin, we used our Transcend Permeability modifiers to increase production by over 60% compared to previous completion methods. The Transcend Permeability Enhancer portfolio is our premier offering for flow-enhancing technology. Using proprietary micro motion technology, Transcend Enhancers expand the reservoir contact area and improve fluid flow to increase the recovery factor for our customers.

For unconventional mature fields, we developed the BaraShield light fluid system tailored to reservoirs' with salt formations and low-fracture pressure to reduce circulation loss and washout. This custom tailoring allows us to reduce mud loss, increase drilling efficiency and ensures zonal isolation for an efficient completion. In today's environment, it's crucial that technology be adaptable to customer demands and improves efficiency.

During the second quarter, our industry-leading cementing technology, NeoCem, was used in over 350 wells per month, including cementing the longest onshore lateral in history, a well that we are now completing. NeoCem delivers high-performance compressor strength, elasticity and shear bond at lower density than conventional systems, saving time and providing improved performance.

Now these 3 examples show the creativity of our chemistry-based research and development teams. We have terrific engineers and scientists looking at every way we can create efficiencies, reduce cost and make more barrels.

Internally, we have similar initiatives of continuous improvement, including: reducing the time for R&D projects to come to market like our very deep resistivity tool, which went from design to field in only 9 months; our surface efficiency initiatives with hydraulic fracturing that reduce the downtime between stages. We are always pushing to improve our processes and optimize the services that we bring to market.

Overall, I am confident about Halliburton's ability to grow North America margins and maintain the run rate for our international business for the remainder of the year. Our strategy is working well, and we intend to stay the course. We'll continue to drive superior execution and remain absolutely focused on delivering best-in-class returns. North America is clearly serving as the world's swing producer, which means this is where the game will be played, and Halliburton is the distinct leader in this market.

Now I'd like to welcome Chris Weber to the Halliburton team as our new CFO. Throughout his career, he has worked in consulting, operations and finance with significant international experience. These combined traits will help Halliburton, and they make him an excellent fit for our team.

With that, I'm going to turn the call over to Chris to provide some details around our financials. Chris?

Thanks, Jeff, and good morning, everyone. Let's start with a summary of our second quarter results compared sequentially to our first quarter results. Total company revenue for the quarter was $5 billion, representing an increase of 16%, while operating income doubled to $408 million. These results were primarily driven by the improved activity and pricing in our Completion and Production division in North America.

Now let me compare our divisional results to the first quarter of 2017. In our Completion and Production division, second quarter revenue increased by 20%, while operating income increased 170%, primarily driven by increased activity and pricing in our U.S. land pressure pumping business. We also experienced increased well completion activity, primarily in the Gulf of Mexico, North Sea and Russia, partially offset by pricing pressure in the Middle East.

Turning to our Drilling and Evaluation division. Revenue and operating income increased by 9% and 2%, respectively, primarily due to increased U.S. drilling activity. In the United States, our Drilling and Evaluation revenue grew in line with rig count. On the international side, revenue was up due to increased drilling activity in Latin America, North Sea and Russia, partially offset by price pressure across the international markets.

Now let me take a minute to compare our geographic results. In North America, revenue increased 24% sequentially, primarily driven by continued improvement in pricing and activity in our U.S. land business, particularly our pressure pumping and well construction product service lines, as well as higher completion tool sales in the Gulf of Mexico. In Latin America, we saw revenue increase by 10%, primarily driven by increased drilling activity in Mexico, Venezuela and Colombia as well as higher stimulation activity in Argentina.

Turning to Europe/Africa/CIS. Revenue increased 12%, primarily due to a seasonal rebound in the North Sea in Russia, resulting in higher drilling, well completions and pipeline and process service activity.

For Middle East/Asia, revenue increased 2%, primarily as a result of increased fluid services in Asia Pac and higher wireline and well completion activity in the Middle East. Partially offsetting these increases was pricing pressure throughout the region as well as declines in fluid and stimulation services in the Middle East.

Our Corporate and other expense totaled $114 million in the second quarter, which was higher than originally anticipated, primarily due to approximately $42 million in litigation settlements and onetime executive compensation expense during the quarter, of which $29 million is a loss contingency in connection with an understanding with the SEC staff to settle the previously disclosed investigation of certain past matters related to our operations in Angola and Iraq. The settlement is pending approval by the commissioners of the SEC. Separately, the DOJ has advised us that it has completed its investigation of these matters and will not be taking any action. We anticipate that our corporate expenses will be approximately $70 million for the third quarter of 2017.

During the quarter, we also recognized a pretax charge of $262 million for a fair market adjustment, which is required by accounting rules related to an expected exchange of $375 million of our Venezuela receivables for an interest-bearing promissory note of that same value. This note is with our long-standing primary customer in Venezuela. Similar to the Venezuela notes exchange we did in the second quarter of 2016, this new instrument will provide a defined payment schedule while generating a return. We intend to hold the notes to maturity and expect to collect 100% of the principal. It's important to note that to date, we have received all payments required by the 2016 notes.

As a function of our reduced debt balance, we reported $121 million in net interest expense for the quarter. Looking ahead, we expect net interest expense for the third quarter to remain at a similar level.

Our effective tax rate for the second quarter came in lower than expected at approximately 23% due to certain discrete items related to prior year audits. For the remainder of 2017, we still expect the effective tax rate to be approximately 29% to 30%.

Cash flow from operations during the second quarter was approximately $350 million, and we ended the quarter with approximately $2.1 billion in cash and equivalents. These results were largely driven by an improvement in days sales outstanding. Historically, our annual cash flow is back end-loaded for the year, and we don't believe that 2017 will be any different. Continued improvement in our earnings and a number of working capital initiatives should strengthen our cash generated from operations as the year progresses.

Now I would like to provide some color on our near-term operational outlook. The macro market dynamics make forecasting a challenge, but this is how we see the third quarter playing out. For our Completion and Production division, we expect that our North America sequential revenue will outperform average U.S. land rig count, while international revenue will remain flat. In addition, we expect margins for the division to increase by 225 to 325 basis points. In our Drilling and Evaluation division, we are anticipating North America revenue will grow in line with the average U.S. land rig count, while the international market will remain flat to slightly down. We expect margins for this division to remain relatively flat sequentially.

Now I'll turn the call back over to Jeff for a few closing comments. Jeff?

In closing, there are a few things I want to highlight. Our second quarter results clearly demonstrated the strength of our franchise in North America and our ability to adapt to a rapidly changing environment. If you believe in energy, you should be invested in North America.

Halliburton's relative performance for the balance of the year will remain strong as a result of our ability to grow our North America margins and continue to maintain revenue and margins in our international business. Our strategy is working well, and we intend to stay the course. We will continue to drive superior execution and remain focused on delivering best-in-class returns.

I want to take a moment to thank Dave for his leadership of Halliburton during his 17 years as CEO. He created an amazing legacy, and our employees, customers and shareholders have benefited greatly from his management of our company. I've had the pleasure of working with Dave for almost 30 years. He's an important mentor to me. Together, we developed a strategy and leadership team for our company, and I look forward to working with him over the next 18 months.

Before we open the call up for questions, I'll go ahead and ask the first one myself because I know it's on everyone's mind. What are we doing around newbuild equipment? The simple answer is that we are, first and foremost, a returns-focused organization. We have the ability to make a series of discrete decisions around equipment, and we'll only bring it out under certain conditions: first, that it's backed by customer commitment; second, that it captures leading-edge pricing, which is accretive to our margins; and finally, it generates acceptable return on investment.

So let me remind everyone that we have not invested in our legacy fleet in 2.5 years. Prudently managing the health of our fleet is important to maintain the type of service quality and reliability that our customers have come to expect. Therefore, some replacement of equipment will be necessary over time. Our manufacturing center in Duncan is a powerful competitive differentiator for our organization. It allows us to be nimble and build equipment as needed with short lead times. This flexibility allows us to control the rate at which we manufacture, building as little as 2,000 horsepower at a time if need be.

We delivered what we said we would on the reactivation plan. When we build additional equipment, we'll do it with the same discipline around returns. Halliburton is the execution company, and you have to trust me to do the right thing: run the business in the right way and make the right decisions. That answers it.

Now let's open it up for other questions.

(Operator Instructions) Our first question comes from Judd Bailey of Wells Fargo.

First, let me say, Dave, congratulations on a great career as CEO of Halliburton. I enjoyed working with you the last several years.

The same back at you.

First question, I wanted to just circle back on the impact of reactivations in 2Q and how to think about the -- any impact on the third quarter. It was talked about in terms of impacting -- negatively impacting margins on your first quarter call. You still had incrementals in C&P close to 50%. Could you maybe walk us through how you were able to offset some of the reactivation costs? And then to what extent will reactivation cost impact the third quarter? And do you intend to reactivate any more equipment? Or is it more refurbs or newbuilds at this front -- at this point?

Look, Judd, thanks. Bottom line is the costs were lower than expected in Q2, and that's because we got there faster and cheaper than we thought. Our Duncan manufacturing team just simply way outperformed, both by speed and bringing down the cost of everything. The other thing that happened was our people went back to work faster, and that's principally because of all the demand that we saw for our equipment. I'd suppose one other thing is we were successful in bringing back a large quantity of former Halliburton employees, which is something we always wanted to do. But that also means that they go back to work more quickly with substantially less training. But as we look ahead to Q3, obviously, there'll be new challenges to deal with. For example, our employees. Our employees haven't had raises in 3 years, and so we plan to, for example, provide our employees with raises. But what I would like you to do is listen to Chris' guidance on Completion and Production. We've said we'll outperformed the rig count growth on revenue and continue to improve margins. So that's really how we see that.

Okay. And I guess just as my follow-up, just to kind of think about the progression on, I'll just stick there to C&P for now. One of the scenarios that's talked about, if oil prices stay between $45 and $50, is that we continue to step up in terms of completion activity next couple of quarters and then maybe level off. Do we -- is getting to normalized margins a realistic scenario in your mind? And if so, do we hit those by the fourth quarter? Or can we -- would it be reasonable to anticipate being at normalized margins next year if activity were to kind of level off at 4Q levels?

Well, look, we're not backing off our expectation on normalized margins. As I'd said, it -- and I won't give you a date but I don't have a crystal ball, but I expect it would be into 2018. But it starts with customer urgency, as I've described. And that really means having targets to meet targets, and that's where we absolutely shine it on. That's what our value proposition does. And we still see supply and demand tightness. I mean, our calendar is full as we look out, and so I don't see any change in my outlook.

And our next question comes from James West of Evercore ISI.

And, Dave, my congrats as well on one hell of a run at Halliburton.

Thank you.

Jeff, I know you've answered my question already to a certain extent at the end of your prepared comments there. But as we think about newbuilds in the market, you laid out your 3 criteria for newbuilds. Are we at those criteria yet? And are you contemplating newbuilds kind of as we speak besides replacements -- incremental newbuilds?

Yes. Look, I'm going to go back to what I said on this, James. And man, I'd be crazy to lay out our market strategy in detail here. But I laid out the conditions, which is committed client contracts -- or commitment from clients, leading-edge pricing and then the ability to generate adequate returns. Short answer is we haven't built anything so far this quarter. But I would say if the opportunity above does present itself, then we have the ability and the capability to quickly meet that demand with Duncan.

Okay, fair enough. And then, Jeff, as my follow-up here, we have seen some additions by smaller companies that are mostly the ones that have either IPO-ed or are trying to IPO and need to show some growth to do that. But as you look at your major competitors and look across the pressure pumping marketplace, do you see much additional -- or incremental horsepower being added outside of kind of what's probably the natural attrition in the market?

No. I mean, our view had always been that there would be attrition. We see that. And today, our view of the market is, in fact, sold out. That's part of the reason we see DUCs building and other things. And we've really got the same amount of horsepower that's been in the market. It's changed hands in a couple of instances. But with respect to the headline amount of horsepower that was there in '14, we're well short of that today.

And our next question comes from Bill Herbert of Simmons.

Jeff, a quick question here for you. Just given the absence of reactivation friction or at least not as much in the third quarter, a sort of pricing that you're gleaning given the undersupply nature of the frac market and the sense of urgency that you talked about and a leveling off of the supply chain inflation and yes, you sort of mentioned some wage inflation, but why wouldn't incrementals in the third quarter for C&P be better than what they were in the second quarter? Because your guidance implies, assuming a low double-digit rate of revenue expansion, somewhere kind of in the 40% to 45% incremental margin range. That strikes me as conservative based upon the facts as you have laid them out.

Well, first of all, I won't lay all of that out, but let's think about what Dave said in terms of tapping the brakes. And so we see some tapping of the brakes, which, in my view, better described as, let's say, going from 80 miles an hour to 70 miles an hour. But it hasn't limited the ability to push on price, and our guys are absolutely doing that every day. And as I'd said, we still see the customer urgency. So we are moving on price all of the time. But I think that if we go back to Chris' guidance, I mean, that's solid progress, particularly as I described kind of the macro environment that we, I guess, all had talked about.

Okay. With regard to the cadence of reactivations during the second quarter, would you describe those as having been relatively evenly distributed over the course of Q2, front end-loaded or back end-loaded?

Ratable sort of Q1, Q2. There was no particularly weighting one way or the other.

And our next question comes from Angie Sedita of UBS.

Certainly an impressive quarter to be your last one, Dave, and you will certainly be missed. And we wish you well in your new role.

Thank you.

So on the question, for Jeff or Dave, on the completion of frac intensity, is it fair to say that you haven't seen that yet peak? And if so, when you think about North American revenues going into 2018 in a flat rig market, should we still see revenue starting to flatten out as well? Or could you see still some growth in that revenue cadence with the completion intensity that's off in 2018 and is flattening a rig market?

Well, Angie, it's, I mean, too early to call on '18. I -- what I would say is the pace that we see, we see a solid ramp in terms of our ability to execute and deliver on the things that we've talked about with respect to normalized margins. We do see currently DUCs building. There's backend weighting to activity. And quite frankly, the science continues to drive the business. And so I think in terms of peak, the peak is going to be probably more science-based in the future and maybe less volume-driven.

All right, fair enough. And then on pricing in pressure pumping, thoughts on the outlook for pricing as we go into the back half of '17 and even into '18. Have you started to see a deceleration in the recent weeks? And then again, going back to that flat rig market, thoughts on pricing in a flat rig market?

Well, as I'd said, Angie, I'm not going to lay out our pricing strategy here on this call by any means. What I would go back to is we push price all the time. Our guy -- what we do is in high demand. And particularly in a market like we're in now, where urgency matters, delivering targets matters to our customers, and that's where hyper-efficiency and the technology that we bring are so valuable. And so I am confident that we are continuing to work. We talked about the leverage that we have in terms of leading-edge price, the legacy fleet and then, obviously, cost and efficiency. And so we work on all of those all the time.

And our next question comes from Sean Meakim with JP Morgan.

So Jeff, you made a point of emphasis around sand demand perhaps starting to get smarter. But is it fair to say that service intensity likely continues to increase on an average well basis going forward? And how do you characterize the rate of change on overall service intensity?

Yes, the intensity continues to increase, both rate and numbers of stages and those sorts of things. So I think it's more of -- I bring it up simply because I have always believed that sand A is not infinite, and it's not free. And so as we started to put constraints on sand in terms of availability and cost, it's actually had a very rational impact on driving thought around where it goes and how much in terms of total volume. But I would say in terms of how it gets placed -- and I talked about a couple of technology examples in my prepared remarks. But those are the kind of things that the equipment works just as hard, but it is how it's applied. And so that's why I bring that up, that we haven't seen that before, really, gosh, in 5 years, 6 years. And so it's one data point, but it's one that I'm certainly going to watch.

Absolutely. And then just wanted also to touch base on the acquisition on Summit. Can you give us maybe a little more detail on the expansion strategy for that new business? And just as you think about M&A, are there other tuck-ins needed to keep filling out that lift portfolio? Or can you build off of Summit here to really get where you think you need to go?

Yes. Thanks, Sean. I mean, the Summit deal is a fantastic fit and fantastic people is what I can say about that. I mean, it was a great add for our Artificial Lift business. When we put our business together with Summit, it creates a solid #2 position in U.S. ESP. Love their technology and really love their value proposition. I mean, they are so dialed in to how they respond to customers, and they've built the plumbing around that to do it very, very well. And so the strategy going forward is to use our footprint to create even more value, which we know we can do, starting here in the U.S., but also internationally. We've talked about M&A before. And I don't see -- we continue to be interested in growing our production group, which includes all forms of lift. Happy with where we've gotten to on ESP today. And then I've also talked about chemicals being probably more organic and less M&A. But nevertheless, there'd be some M&A in that.

And our next question comes from Jim Wicklund of Crédit Suisse.

And, Dave, it's been a fabulous almost 2 decades, but you're not gone yet. So we'll see you other than on the conference call, but congratulations on a great run.

You're right, and I am not gone yet.

No, I got to bring that up, make sure everybody understands he's hanging around for 18 more months. Jeff, you make an excellent point on the pricing of international, saying that while overall activity is quick going down, there's not enough bulk of activity in several markets to really get pricing improvement. Where do you expect to see internationally the first level of activity getting high enough that we're not giving away price anymore and a beginning of recovery?

Well, Jim, it's going to be in some spot where there's a discovery or there is enough sort of base load of activity to move quickly. If I had to guess, there's probably some places in Latin America that might fill that bill. But as far as a broad region, that's really part of the issue, Jim. It's like peanut better being spread around the world and it never gets enough traction in a particular spot. And so that's why -- what makes it tough is simply because it will be very concentrated in a place when we start to see that. Now the other side of that, that's one of the reasons we do protect our international franchise. We think that the investment we made over the last several years is valuable and will be more valuable in the future when that time comes. But it's not -- I think we're moving sideways for a little while.

And in Drilling and Evaluation, you note that you had a $150 million increase in revenue but only a $3 million increase in income, and that clearly points to price issues. I'm just wondering, you had a seasonal recovery in the North Sea and in Russia, and those are 2 places we normally don't associate with Halliburton being leading-edge. Were those 2 of your better markets or your worse markets? Can you talk about just on the Drilling and Evaluation side where those 2 markets fit?

Yes. I mean, on a relative basis, relatively smaller. But quite frankly, very good markets for us. And once -- I really want to give kudos to Joe Rainey and that team, who have absolutely executed and built those businesses. So those are businesses that are, in my view, gaining traction in the D&A part of our business; better alignment around customers; I think closer alignment with customers, particularly in Russia today; and very encouraging.

And our next question comes from David Anderson of Barclays.

So Dave, all that time on the road, I think you've earned your downtime. Good luck on your next venture there.

Great. Appreciate it.

So Jeff, I just wonder if you could talk a little bit about the pricing a slightly different way. You talk about getting leading-edge pricing on your reactivated equipment, but I'm curious about your legacy fleets out there. I think there's still one area you've been trying to keep that, you want to keep those relationships there. What's that spread now in the pricing between legacy and kind of new equipment going in the market? And when do you think that starts to close? Is that a year-in? Is that kind of a 12 months it takes to close that gap? What's your thoughts there?

Look, that's something that is closing, I'd say, sort of every day as we work it. It's -- but let's go back to why there is a spread there. And it's because we're aligned with very good customers. They're very efficient, and so we want to be part of their business. And we believe we can do a lot to help drive down sort of their overall cost and lower their cost per BOE. And so that's why we never had a -- we abandoned half the market to go move somewhere else. We absolutely want to support all of our customers. So I'm not going to give you that spread. But I will tell you it's something that I think I'd said in Q1 that we would be closing in on that over 4 quarters, so look for some time early in '18 to have that done.

Okay, great. And then on -- in terms of your fleet now, what percentage of your overall fleet has your modern Q10 pump out there? And I was wondering if you could expand a little bit upon that pump and how that changes in terms of the useful life of your equipment versus what's out there in the market. You touched on it before about the attrition out there, but just trying to get kind of a sense as to kind of how your equipment is different in the market than other equipment out there and why we should think about that differently.

Yes. So I mean, I would say we're probably in the 60% range or so for the following reactivation. The important thing about that equipment is that it is built for total cost of ownership. I mean, we don't sell this equipment in the market. Our guys at Duncan are absolutely motivated by one thing: what is the most resilient, efficient piece of equipment? And I go out and check to make sure that it's competitively priced, which it is. But more important than its cost is what it does for our guys in the field and the way that it's integrated. So it runs at higher rates. It uses all available horsepower. It's more efficient by still about a 20% efficiency compared to what we see in the market. So when I think about how do we make the best returns in the marketplace, we always think about how do we drive capital off of a location. And the first thing to do is have more efficient pumps on location.

And our next question comes from Kurt Hallead of RBC.

And, Dave, congratulations and all the best.

Thanks.

So Jeff, you brought up a very interesting comment a little bit earlier about seeing the first quarter here, where sand use per well has declined. I was wondering if you might be able to elaborate on that a little bit more. Do you sense that it -- as you mentioned, that it is truly purely an economic decision? Do you think it's an anomaly? Do you think there, the shortage of sand that's driving it? Just kind of getting -- trying to look for a little bit more color on what you may be seeing.

Look, I think it really is part of the science of frac, and that is -- it's not the only thing. It's not that customers are running from the economics, but they are making very thoughtful economic decisions. And as the availability -- or actually, the applicability of science and the better they understand and we collectively understand how to make more barrels, that gets put to work with clearly an economic backdrop. And I think that back to Dave's earlier comments on our customers, I mean, this is an incredibly adaptive group of customers that I think have demonstrated through the toughest cycle in our history an ability to consume science, consume lessons learned and move the cost per BOE down almost in the face of anything. And so I think what you're seeing is really the natural evolution of, "Okay, as inputs move up, what are better ways to get more barrels?" And in some cases, we're seeing that. This is not across the board. But on an overall basis, that was the data point we saw.

Okay. And just maybe on the international front. I know you mentioned the spreading of peanut better analogy, but it seems like there's more concentrated increased activity levels going on in Latin America and in a number of different countries. Do you feel like you could get pricing power moving in the right direction in Latin America before some other regions?

Well, again, I'm not going to get our strategy around price anywhere. But what I would say, Latin America is not too different in terms of the contract cycle in terms of -- the length of contracts typically have a muting impact. There's plenty of -- quite a bit of equipment in the world today. And so certainly, look forward to that, but I would not -- it's not enough to change the overall trajectory.

And our next question comes from Waqar Syed of Goldman Sachs.

Dave, congratulations again, and you'll certainly be missed. Your comments and -- would be missed greatly on the calls.

Appreciate it.

My question relates to the Permian sand that's been recently -- a lot of new capacity additions have been announced. And there's a good chance that prices are going to fall quite sharply in the Permian for E&P companies there. What impact does that have for pressure pumping companies as sand prices fall in the Permian? Is it neutral? Or is it negative or positive? And then also, how do you think about your own investments in transloading and rail transportation? Would that change if most of the sand is recently sourced?

Look, that's great for us. It's good for our customers. It's good for us in terms of lowering cost per BOE. I've been fairly vocal about why we don't own mines, and that's -- this is an example of why not and from Halliburton's standpoint, why we wouldn't want to be invested and tied with sump costs to a place as technology moves a different direction. The transload infrastructure that we have is valuable. I would say the -- probably the toughest spot to get to realistically is the Permian Basin. And local sand, in my view, opens up a whole new avenue of what is lower cost. And some of the things that we're doing around delivering sand, we're always looking at how do we get sand delivered at a lower cost point. And I think our containerized solutions that we're implementing are right in the sweet spot of that kind of development.

Okay. And you don't see -- are there any long-term negative implications, or cost implications for rail cars or other things that you may have leased or the industry may have leased?

No. I mean, the stuff works all over the country, and that's a fairly localized solution. So I like what we're invested in, and we've always been careful. Again, to -- we target about 50% of our capacity is managed internally, and we do that so that we can flex with the market. And that's how I see this.

And our next question comes from Ole Slorer of Morgan Stanley.

And again, Dave, congratulations with a very solid run at Halliburton.

Thank you.

Jeff, a quick question to you, again regarding kind of the sand logistics and the changes in completions again. I mean before you highlighted that, that Halliburton doesn't really have an interest in owning sand, but wants to focus on the logistics because of the changing nature of the type of proppant that's preferred. So could you talk a little bit about the kind of capacity that's being added at the moment in West Texas? It's kind of 100-mesh largely and some 40/70. And address that in context of other proppant and how you see the mix evolving and how that impacts Halliburton.

Well, look, I -- we're in large part agnostic to the type of sand. The reality is we study sand closely to understand how to better design chemistry to make better fracs. Cost is always a component of that, but we've seen other media sort of go into vogue and out of vogue. And we've got MicroScout, which is a nano-style solution -- a micro-style solution. So I think that, obviously, what's being talked about today is consistent with what I hear from customers and what is being consumed today. But again, the drive for better science is always going on, and that's one of the reasons our labs are constantly looking at how to take what's available and make it better and how to either -- or to substitute with things that are better. So I think that's the answer and hoping it's appropriate.

So in your view, the reduction that you saw on a per-well basis, was that a function of shortages of sand pricing and therefore, forcing the industry to adopt different methods? Or do you see this trend continuing even as kind of sand gets debottlenecked?

Well, it's one data point, and so I will clearly be watching that. The sense that I get is more around design and what is the most -- I mean, our clients are dead focused on lowest cost per BOE, making more barrels and at a lower cost. And so designing things that can consume less sand but deliver more barrels or as many barrels is clearly what they want to do.

And that concludes our question-and-answer session for today. I'd like to turn the conference back over to Jeff Miller for any closing remarks.

Thank you, Candace. Before we close, there are a couple of points I'd like to highlight. First, our second quarter performance demonstrates the strength of our North American franchise and our ability to adapt to a rapidly changing environment. Second, Halliburton's relative performance for the balance of this year will remain strong as a result of our ability to grow North America margins and maintain revenue and margins internationally.

Look forward to talking with you next quarter. Candace, you may now close out the call.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Have a great day, everyone.