Good day, ladies and gentlemen, welcome to the Halliburton third quarter 2016 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. If anyone requires operator assistance, please press the star then zero key on your touch-tone telephone. As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Lance Loeffler, Halliburton's Vice President of Investor Relations. Sir, you may begin.
Good morning, welcome to the Halliburton third quarter 2016 conference call. Today's call is being webcast, and a replay will be available on Halliburton's website for seven days. Joining me today are Dave Lesar, CEO, Mark McCollum, CFO, and Jeff Miller, President. 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 31st, 2015, Form 10-Q for the quarter ended June 30th, 2016, 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 may include non-GAAP financial measures.
Additional details and reconciliation to the most directly comparable GAAP financial measures are included in our third quarter press release, which can be found on our website. Now I'll turn the call over to Dave.
Thank you, Lance, and good morning to everyone. Let me start by saying that I am very pleased with our results. I never thought I would be so satisfied by barely making a profit, but given where this market is, I certainly am. Through hard work and determination, we have returned to positive territory for our earnings. This has been a historic down cycle for the industry and has had its fair share of challenges. Our organization is meeting those challenges head-on and fighting through them. I am very proud of our leadership and all of our employees. We are the execution company, and I believe this quarter we outexecuted even the very high expectations we place on our organization. Let's take a minute and talk about what transpired over the quarter. Our North America revenue grew 9% for the period, representing the first revenue increase in seven quarters.
Our results improved as we took advantage of the rig count growth by focusing on increasing utilization and working our surface efficiency model. Our customers' animal spirits remain alive and well in North America, even though for some, they may feel caged in a bit by cash flow constraints in the short term. The average U.S. rig count increased 14% over the quarter, driven primarily by rig additions to smaller operators, where we saw a trend of less service-intensive wells, which is not activity typically worth chasing at today's pricing. This quarter was also impacted by the natural lag time between drilling and completion activity. However, we are now seeing completion activity starting to pick up as we start the fourth quarter. We continued to aggressively implement our structural cost reductions announced in our first quarter call. We have met our goal.
On a monthly basis, we have already achieved a run rate of $1 billion of cost savings annually. We also generated over $1 billion in cash flow from operating activities this quarter. As you all know, as we executed our playbook, we gained significant market share globally through the downturn. As the markets stabilize, our primary focus will now switch to improving our margins while maintaining that market share. In the U.S., we believe we now have the highest market share we've ever had. At this point, if we have to give some of it back to move margins up, we might take that approach. In North America, we achieved a 41% incremental margin. This is a strong step in the right direction as we work to regain profitability there.
We remain steadfast in our belief that significant activity increases from our customers starts with sustainable commodity prices over $50 per barrel, which we haven't seen in any meaningful way yet since the rig count activity bottomed out. Operators have had time to reflect on their future drilling plans. I believe they will approach the recovery with a rational, methodical response in activity based on commodity price fluctuations. Looking ahead to the fourth quarter on North America land. Activity levels are difficult to call at this point. Based on current customer feedback, we remain cautious around customer activity due to holiday and seasonal weather-related downtimes. Our customers may take extended breaks starting as early as Thanksgiving and push additional work to the first quarter of 2017.
As one customer told me, "Dave, it doesn't make any sense for me to rent an efficient high-spec rig if I have to start and stop all the time for the holidays." Or the last five weeks of the year. I just can't get the efficiencies I'm paying for in the rig. I'd rather just wait till next year to start drilling. I believe we'll see a lot of that mentality in the fourth quarter. That being said, it does not change our view that things are getting better for us and our customers. Let's turn internationally. I like where our market share is today in the international markets. I believe we continue to outperform our peers. I expect the international markets to slowly grind downward due to the lower commodity price environment.
We experienced activity in pricing headwinds during the quarter. In anticipation of those forces, we aggressively managed our costs. Although we have had to concede some on pricing, we have worked closely with our customers during the past year to improve their project economics through technology and operating efficiency. We expect to see a bottoming of the international rig count in the first half of 2017. Land-based mature field activity should lead the international recovery, while we expect the deepwater complex to remain severely challenged for the foreseeable future. Even though the light at the end of the tunnel is getting brighter, there is no question we remain in a very challenging market. We are confident in our ability to navigate through this cycle and in our continued focus on unconventional mature fields and deepwater markets.
As we have said before, unconventionals, particularly those in North America, are leading the recovery in activity, providing the optimal combination of short cycle returns and fastest incremental barrel to market. Mature fields continue to be resilient given their relatively low lifting costs. Finally, deepwater remains structurally challenged with higher costs and long-duration project characteristics. While each faces a different set of circumstances today, you can be sure we are looking at our business closely to ensure that we accelerate our growth in each sector as the industry begins to heal. As we have said for some time, North America has assumed the role of swing producer in global oil production. Because of the shift away from production discipline, which was historically created by OPEC, our industry will likely experience shorter commodity price cycles going forward.
We see the future market as a combination of shorter cycles and range-bound commodity prices. In that environment, it is imperative that returns-focused companies like Halliburton be more asset light. Having an organization structured in a way that is flexible, nimble and efficient, and that can adapt to these new, quick-moving cycles will be critical to drive the returns results our shareholders have come to expect. Our philosophy has been in prioritizing returns over margins and revenue. That philosophy will continue. Now, don't get me wrong, we are always focused on improving margins. Keep in mind the last cycle of $100 oil covered up terrible inefficiencies across the industry. In today's environment, asset utilization will be just as critical to improving margins. I have full confidence we are taking the necessary steps to achieve that.
Positioning us for success while navigating through this deep cyclical downturn was one of the most intellectually stimulating management challenges we have ever had. I am confident the Halliburton management team has and will continue to successfully meet each and every challenge. With that, let me turn the call over to Mark and Jeff to cover our financial and operational results. Mark?
Thanks, Dave. Good morning, everyone. Let's start with a summary of our third quarter results compared to our second quarter results on an adjusted basis. Total company revenue for the quarter was flat at $3.8 billion, while our operating income doubled to $128 million. These results were primarily driven by increased activity in North America and the continued impact of our global cost savings initiatives. Moving to our regional results, North America revenue increased 9% with a $58 million increase in operating results, or 47% sequentially. The higher U.S. land rig count, coupled with better equipment utilization and our ongoing cost management efforts, drove this improvement. In Latin America, revenue and operating income declined by 13% and 50% respectively. These results primarily reflect reduced activity levels in Mexico, Argentina, and Venezuela, as we've now experienced a 15-year low in the regional rig count.
Turning to Europe, Africa, CIS, revenue declined 6% as a result of lower drilling activity in West Africa and continental Europe. Operating income increased 19%, primarily related to our cost savings initiatives and improved pressure pumping and pipeline service profitability throughout the region. In Middle East Asia, revenue declined 3%, with a decline in operating income of 4%. The decrease for the quarter was primarily driven by reduced activity across Asia Pacific, including Australia and Indonesia, as well as pricing pressure across the entire region. Our corporate and other expense for the third quarter totaled approximately $47 million, which was positively impacted by a true-up of some of our insurance reserves. For the fourth quarter, we expect our corporate expense to return to our previous run rate of approximately $60 million.
Interest expense for the quarter was $141 million and was positively impacted by the interest income we're now earning on the Venezuelan promissory notes we accepted in exchange for some of our trade receivables last quarter. We expect that this level of net interest expense will be our new run rate for the next several quarters. Our effective tax rate for the third quarter was 114% benefit, well above the already unusual 50% rate we anticipated on our last call. As we've discussed before, these unusual effective tax rates are primarily the result of having tax losses in the U.S. that are offset by taxable income in foreign jurisdictions with lower statutory rates.
The difference this quarter from the rate we anticipated was largely due to an adjustment reflecting the beneficial use of an Argentinian tax treaty that limits the taxation of royalty payments for intellectual property and will allow for more efficient movement of our foreign cash in the future. Based on our current outlook, we anticipate that our effective tax rate for the fourth quarter will be approximately 65%. Turning to cash flow, we improved our cash position during the third quarter, ending the period with $3.3 billion in cash and equivalents, even after paying off $600 million of senior notes. This increase in cash flow was primarily due to working capital improvements, which included a seven-plus day reduction of our days sales outstanding and the receipt of a series of tax refunds. Capital expenditures for the year are still expected to be approximately $850 million.
Turning to our short-term operational outlook, let me provide you with our thoughts on the fourth quarter. In North America, the uncertainty surrounding customer activity around the holiday season makes the quarter difficult to predict. Based on what our customers are collectively telling us, we anticipate our revenue to perform in line with the rig count, and we expect our sequential incremental margins to be 35%-40%. In our international business, we believe the typical seasonal uptick in year-end software and product sales will be minimal this year, as customer budgets are exhausted and may not fully offset continued pricing and activity pressures. As such, we expect fourth quarter revenue and margins to come in flat compared to the third quarter. I'll turn the call over to Jeff for the operational update. Jeff?
Thank you, Mark. Good morning, everyone. I'd like to thank and congratulate all of our employees for their fantastic execution throughout the cycle. It's been a tough two years, our organization has delivered on service quality, has delivered on cost savings, and has absolutely executed on our value proposition, collaborating and engineering solutions to maximize asset value for our customers. The result of this execution was improved margins and repeat business. Let's start with North America. While the supply and demand balance for U.S. onshore services is heading in the right direction, we are still in an oversupplied equipment market. Our customers remain focused on cost and producing more barrels. I believe this puts us in an excellent position. No one is better at collaborating with customers to engineer solutions that deliver the lowest cost per BOE than Halliburton.
In fact, the more I talk to customers, the more I am convinced this is the winning formula. In pressure pumping, we estimate that the U.S. active fleet, I emphasize active, grew to over seven million horsepower, and the utilization of that active marketed fleet is about 70%. This is a long way from full capacity, but it represents substantial tightening during the third quarter. As I said last quarter, this is the first step towards a balanced market for the industry's available fleet. While we know the industry has additional horsepower on the sidelines that could come into the market, we also know that this additional equipment requires substantial maintenance to be put back to work and will require adequate price increases to justify its return. As we look ahead, we expect pricing to work its way through a couple of predictable steps.
The first step, which we're starting to see now, is a tightening of active capacity. This will have a modest price impact, but more importantly, it allows increased utilization to have a positive contribution to earnings. Step 2 is when we see equipment requiring significant investment returning to the market. I expect that this will require significantly higher pricing to justify the investment. This is by no means traditional pricing power. Instead, it's the industry recognizing the relationship between investments and returns. Let's hope. Market share is valuable, that's why we build it in the downturn. I think Dave was crystal clear that our target is leading returns, we have not forgotten that. High market share gives us choice in the recovery to work with the most efficient customers who value what we do and who ultimately reward us for helping them make better wells.
There is no doubt that in this environment, our clients are planning work based on commodity price. The stakes have never been higher for us to help maximize the value of their assets. This is exactly what we're doing. Let me take you through some examples of how we're doing this today. Last quarter, we worked with a Permian operator who wanted to step outside of their core assets and find a way to optimize the value of their acreage. With a robust drilling and completion plan in place, the customer sought to minimize completion damage during flowback to maximize overall recovery. Through the use of our Caliber engineered flowback service, we were able to prevent damage and achieve a 15% higher cumulative production on this well than on wells nearby with similar completions.
The well is now the best producer in the customer's portfolio, despite it being in the geology that had been originally considered marginal. There's been a lot of talk about drilling in core reservoir rock recently. I believe it's now our job to help our customers extend the definition of core. This is a great example of how we listen to our customer's drivers and work with them to develop a unique solution to meet their goals. Caliber had not been used before in the Permian, but thanks to this success, it's gained traction in that basin. In the Middle East, we recently engaged in a highly collaborative project where the customer's drivers were to improve delivery time and production. We developed a solution that stimulated a well in less time and in a more cost-effective manner.
Using our SurgiFrac technique, where coiled tubing is used to deliver more focused stimulation to selective areas, we were able to use fewer chemicals and reduce pumping time by 40%. This highlights how Halliburton systematically collaborates with a customer to engineer a solution that maximizes their asset value. In Brazil, we work to maximize our customer's asset value through intelligent completions. These are essential in the pre-salt area to improve reservoir management and production while reducing the overall well cost. In the quarter, we completed a multi-year campaign of 40 successful intelligent completions, which lowered the lifting cost dramatically. This is what clients like about Halliburton. We collaborate, meaning listen and respond to our customers. We focus on creating and maintaining strong client relationships. It's why we win and keep work. It's how we get things done and why we are the execution company.
To sum up, I've walked through our value proposition in action. It's equally effective in all of our strategic markets: unconventionals, mature fields, and deep water. The takeaway is that Halliburton is well positioned to win the recovery in each of these markets. Now I'll turn the call over to Dave for closing comments. Dave?
Thanks, Jeff. Let me summarize. As we predicted, the North America unconventional market has responded the quickest, demonstrated by the increase in recent rig count activity. However, we continue to believe meaningful activity increases from our customers will not start until we see sustainable commodity prices above $50 per barrel. While the international markets will take a little more time to rebound, we are maintaining our integrated global services footprint, managing costs, and continuing to fight for market share. We expect to see the bottom for activity in this market to occur in the first half of 2017. In this global recovery, we expect cycle times to accelerate. I believe successful companies will be characterized by a lighter asset base, faster asset velocity, and job site execution, all geared to respond quickly to deliver returns.
To me, no matter what market is handed to us, Halliburton is well positioned. Our dedication to execution gives me confidence that we will continue to outperform our peers. With that, let's open it up for questions.
Thank you. Ladies and gentlemen, if you wish to ask a question at this time, please press star then one on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. As a reminder, please limit yourself to one question and one follow-up. Our first question is from James West with Evercore ISI. You may begin.
Hey, good morning, gentlemen. Congrats on a well-executed quarter.
Thank you, James.
I wanted to dig in, Dave or Jeff, on the pricing question around North American pressure pumping. At this point, I know you've indicated you've got the market share, so you'll give up some in order to get profitability up. Are you starting to see the early signs of some pricing gains in certain basins? Maybe it's not in the Permian, but maybe some of the basins where equipment has migrated out of?
Well, thanks, James. This is Jeff. Pricing is still, I'll describe it overall as a brawl. As I said, we're always pushing on pricing. We are seeing small increases in different basins, where we're most focused are on those customers with whom we collaborate the best.
Right.
I've always said that the tightening of utilization was a critical first step, and we are beginning to see that. We're also moving away in some cases from work where we don't see a similar clear path to returns.
Okay, maybe a follow-up on that. I guess your strategy for unstacking equipment at this point, you suggested it's more of a conversation about the returns on the assets. I would assume that you need at least some level of price increase to bring stacked equipment, even if it's in great shape, back to work.
Spot on, James. The equipment's got to make returns. In my view, this does require a step up in price. For that reason, we don't have current plans to add horsepower to the market. We expect the next round of investment broadly to drive better discipline related to returns.
Okay, great. Thanks, Jeff.
Thanks.
Thank you. Our next question is from Judd Bailey with Wells Fargo. You may begin.
Thanks. Good morning. Question for Dave or Jeff. I was hoping, could you expand maybe Dave, on your comments and your prepared comments on the need to be asset light? I think you said in the context of a shorter cycle that you envision. Does this reflect any type of change in how you're going to run the business or strategy or how you think about investing in the business, given your comments?
Yeah, Judd, this is Jeff. We're focused on everything that drives returns. In my view the shorter cycles are really closer to our value proposition, which is execution in the last mile. For example, it's not vertical integration for the sake of integration and it's variabilizing everything that makes sense to variabilize in our business. Therefore we're improving margins through better utilization and obviously pricing. Velocity as we come out of this will be more important than ever, and we continue to do things to drive that velocity in all parts of our business. We clearly believe this is how we drive leading industry returns.
Okay. Thank you for that. I guess my follow-up is the guidance for North America in the fourth quarter is I think pretty straightforward. I was wondering what kind of visibility you may have in terms of a calendar for the first quarter, early 2017. Obviously, it'll be dependent on where oil prices shake out and what OPEC ultimately does, but it sounds like you've got some customers who are starting to line up work for '17 at this point, and I was wondering if you could perhaps give any color to that effect.
As we talked about Q4, at this point, the board is full, but we're not clear whether that's customer optionality or not. History would say we slow down in the holidays. That would push more work into the first part of next year. Again, that part of the market is not as clear, at this point in time. We're going to manage our cost and manage our business as we look at that to keep the structural cost and savings in place and be absolutely positioned for when the recovery happens or when that happens.
This is Mark. I think our general view is that Q1 is going to be better, right? How much better it's going to be is still going to be highly dependent on what the commodity price is going into the first part of next year. We think we're clearly on a path to recovery.
Okay, great. I appreciate it. Congrats again on a good quarter.
Thank you. Our next question is from Scott Gruber with Citigroup. You may begin.
Good morning.
Morning.
Hi, Scott.
I was down in the Permian about a month ago, met with a collection of operators, and everyone was discussing more sand per well and longer laterals, two trends that everyone's been discussing for a while. The trend that stuck out to me, which appears less well appreciated, is the trend towards more frac stages per well. A couple of operators were discussing shifting towards 40, 50 stage wells, and one was actually discussing pushing towards 90 stage wells. Are you seeing this trend in the Permian, and if so, can you discuss the impact on the requisite pump time to complete these wells?
Thanks, Scott. Look, we are seeing a move towards shorter spacing on the stages, which ultimately drives more stages. This will drive more service intensity for us. More stages means more plugs, means more perfs, means more sand. You get the point, but just don't forget that the most important thing is making a better well, ultimately, which involves stimulating more rock. I would say that the precise placement of the sand is probably the most important thing, and that's where we spend our time is optimal frac design and placement, and really further, precisely why we focus so much around subsurface insight and ultimately how to make a better well.
Got it. Just generally, are you seeing operators outside of the Permian squeeze the spacing as well, or is this just a Permian phenomenon?
Look, I'd say that what's right is what's right for the rock, and I think you're seeing that move in the Permian Basin. Probably less so in other places, though constantly trying new ways to, again, get more sand in the right place as opposed to just more sand.
Got it. Thank you.
Thank you. Our next question is from Angie Sedita with UBS. You may begin.
Thanks. Good morning, guys. I echo the congrats on an impressive quarter given market conditions. Also, Dave, your sense of realism on shorter cycles and range-bound oil prices is certainly appreciated. On the question, I think the first question is for Mark, we're talking about this asset-light model. Do you still see other structural costs that you can be pulling out of the system in North America and internationally into 2017?
I think that we're never finished in terms of reviewing our overall structural cost. Jeff made the comment earlier about variabilizing costs. I think that there are some things that we haven't necessarily always thought of as structural, that they would be variable in the definition of how we would typically look at them. When we talk about variabilizing those, we're talking about possibly looking at do we lease versus buy? Do we turn a depreciation charge into a lease charge? Do we rent versus own?
What can we do to continue to try to increasingly create optionality in our business so that we can flex with the market overall, but more importantly, flex with our customers to making sure as they continue to evaluate how they want to do their wells or where they want to do their wells, that we can move with them and be as nimble as possible. I think that we're going to go into next year, and Jeff alluded to this, even though we believe the year will be better, we're going to plan very aggressively flat in terms of our structural cost. Even planning flat requires the organization to continue to really focus in on what can we do from a continuous improvement standpoint to continue to drive out cost. I believe you're never done, and we're going to continue to go for it.
Great. That's very helpful, Mark. Going back to North America, pressure pumping. You've made comments in the past on what you thought the margin outlook would be if you have your fully deployed fleets at full utilization. Can you give us your updated thoughts there?
The?
The currently deployed fleet at full utilization.
Yeah. Well, what I would do is let's go back to kind of a margin progression for the business. In my view, it's a path back rather than a dramatic jump. As we've said, certain things have to happen around equipment tightening and attrition. It starts with making positive operating income, then returning the cost of capital, and then pushing for industry-leading returns. Clearly, we're starting from a lower base, but the formula is very much the same, and it's a formula that we know.
That's right. We're definitely going to need some price, right, to get back toward the historic margins that we've had in the past and the historic returns. The first order of business is get capacity tightened up in the market. We believe the activity levels in the Permian, others, all are serving to work the equipment harder. It's going to tighten up equipment faster, and we're starting to see pricing at the edges, and we'll continue to drive that forward as we hold the line on cost, and we're going to get there. The model's the same, and we just got to execute.
Is it fair to assume that that pricing outlook, that improvement is back half 2017 based on what you know today?
I think we'll start seeing pricing earlier than that. We're working on it every day with every customer and the fringes, and it'll be probably a slow march forward initially until things tighten up and then begin to accelerate. Hopefully, we're going to be pushing as hard as we can to get back to 20% as quick as we can.
Great. Thank you. I'll turn it over. Thanks, Mark.
Thank you. Our next question is from Bill Herbert with Simmons. You may begin.
Thank you. Good morning. Mark, a quick question with regard to the guidance for the fourth quarter. Sensibly, you seem to be waxing a little bit conservative about North American top line and sort of in line with the rig count, or at least the expectation. You've got a loaded frac calendar, according to Jeff's commentary, Dave's commentary, completions lagged activity in the third quarter and now starting to pull through in the fourth quarter. Why wouldn't completions and frac activity and Halliburton's North American top line outpace the rig count in Q4?
Hey, Bill, this is Dave. Let me take that one. I think, as Jeff said, the frac calendar is full, but my 20 years or so of being in charge of this thing shows me that customers like to grab optionality in the fourth quarter by filling the frac calendar. It doesn't always come true that we utilize that work, that calendar can get dumped pretty aggressively toward the end of the year, toward the end of the fourth quarter. We're just cautioning people that we don't know yet. It's really up to our customers as to whether they're going to go forward and turn the optionality into real work. My experience has been some years it happens, but most years they start to pull things off the calendar as the holidays get there.
You've got the added, I think, dimension this year of where the commodity price is, what they can buy. Are they going to spend their money buying strips for next year? Are they going to basically want to continue to use these high-spec rigs in a sporadic way? Or just wait till next year where they can rent them out on a pad and run them for 60, 80, 90, 100 days and get the efficiencies from them. We're just trying to draw a little bit of caution out there that there's probably more variables in this Q4 than typically there might be because we're bouncing off the bottom at this point in time.
Okay. In line with-
Bill, I was going to say the follow on. You also recognize we saw this a little bit in Q3 that as we try to improve our margins and returns on this, we are, in some cases, letting some bad contracts go, things that don't work for us. Making money in order to improve the utilization and profitability on others. It may not necessarily follow directly with the rig count until we hit-
Okay
Michael.
All right. That is helpful. Thank you. Then Dave, in line with your pretty stark but realistic commentary about deep water, I'm just curious as to how you're thinking about your global deep water footprint right now, and whether that represents another significant round of call right-sizing for Halliburton in terms of cost-cutting reductions.
Yeah. Bill, let me let Jeff handle that one, because he's kind of dealing with it every day.
Yeah. No, Bill, we like our footprint around the world, and I think deep water certainly has an important role to play. It's clearly the most stressed today. That's partly just because as we collaborate and look at ways to lower the cost per BOE, that they just don't get as many at-bats. Clearly, it's structurally disadvantaged because of duration, which gets to not only the time value of money, but also the speed with which those barrels meet demand requirements. All of that said, still believe it has an important role. We know how to flex the cost around those facilities. I will tell you, keeping that footprint in place is something we will do. Again, I've described our value proposition around last mile execution. That means you have to be present to win, and we plan to be present.
Okay, thank you.
Thank you. Our next question comes from David Anderson with Barclays. You may begin.
Thank you. I think, Mark, you just kind of touched on what I was going to ask you there. I was just wondering if you could expand a bit on the increased utilization in North America. Is that just continuing to squeeze out the white space? Is it dropping certain customers who aren't as active? It doesn't sound like you're reactivating equipment, and I'm just trying to understand how I should think about utilization going forward, considering you're saying margins are now taking a priority over market share.
Look, we're in a unique point in the market right now where we've got choice because we have market share. As we go through that, it's not one way or the other necessarily. It's all about where we see the path to profitability, those clients that utilize what we do best in the best way so that it's mutually beneficial for both of us. It's not as clear as one or the other by any means, particularly as we work through this part of the market. What I really like is where we're positioned. As I've said, we're not going to add equipment until we see clearly better returns. I think that's going to be prohibitive to others to add equipment until the price moves to where it needs to be.
Clearly, our utilization has gone up quite dramatically as a part of this process. That was a large part of what helped with the margins this quarter. We're going to continue to work that formula here for the next quarter or so.
Okay. Just a follow-up question. One of the other things we're hearing from E&Ps now is going to talk about moving more to slick water fracs. Just wondering how that could potentially change the revenue and margin potential on your pressure pumping business as we move ahead into next year.
Slick water is clearly harder on equipment, and it's something we ought to get paid for. Fortunately, the Q10s were designed to operate more effectively at the higher rates that are demanded by slick water. We're preferentially positioned around that. I would also go further to say that today's market is a mixed bag of frac design. We still see quite a bit of gel, some hybrid, and yes, certainly slick water. When I think about the longer term future of where does it go, the key point is controlling the frac in our view. That's why we study chemistry. We think that it's not one size fits all. It's actually what is the right size for that rock, and that's why we are dead focused on making better wells.
It's always important to remember that Halliburton operates in every basin across the whole of North America. What's happening just in the Midland or Delaware, in the Permian at large, every basin, every rock's different. We go to market the way the customers need to get the best well in those markets. We're uniquely positioned to get the best out of our equipment and out of our projects.
Okay, great. Thank you.
Thank you. Our next question comes from Kurt Hallead with RBC Capital. You may begin.
Yeah, thank you. Good morning.
Morning.
Dave, question for you. You mentioned the shift in the strategy to go asset light. By definition, frac is very asset intensive. I was hoping you'd give a little bit more color around the context of asset light.
Yeah. I think as we've said, it's not a shift in strategy. It's a continuation of a strategy or more a continuation of a philosophy is that we are returns driven first. To the extent we can get by with less assets, we can variabilize our asset base, then we are going to continue to do that. That's really all it means. I don't want anybody to read too much into this. It's just a prioritization of returns. When you are prioritizing returns first, the fewer assets you can do the same amount of work with, the better your returns are going to be, the better your margins are going to be. That's really where we are.
Got it. Then your follow-up on the comment about potentially being willing to give some share for margins. Was that U.S. market specific?
No. We take a look at every basin, every customer, every geography, every day, make those decisions on a real-time basis. It's the benefit of having the market share we have, having the great customer base we have, having the great footprint that we have, allows us the optionality of making those decisions each and every day.
All right. Great. Thanks, Dave.
Thank you. Our next question is from Jim Wicklund with Credit Suisse. You may begin.
Good morning, guys.
Jim.
There has been a lot made about the rigs that have gone to work so far have been low-calorie rigs, private companies by private equity sponsors, drilling wells primarily in the Permian and trying to drill as cheap as they can. It would seem that in your market share progression, that you've gone after bigger companies that work 24/7, that drill complex wells. Has the move so far off the bottom been a rig count that is not terribly beneficial to you guys, and is that one of the issues that will be solved as we get into 2017, and the more established companies pick up drilling?
Well, Jim, the rigs that we're seeing, as you described them, are probably less service intensive. They've also tended to be less about big new capital programs and what we've seen has been more around repairing or trying to sustain a bit of production, which looks and feels quite a bit different. I fully believe, though, that this comes right over the next period of time because, again, where we tend to engage is when they start to make the bigger decisions around how to design fracs, where are we going to be positioned, and getting up to sort of full speed and full velocity. That's when our assets work the hardest, and that's where we're the most efficient. Again, part of being, as Dave said, around asset light is velocity as much as it is anything else.
We're drilling long horizontals, and we're full on. That's where we're absolutely at our best.
Yeah, I have no doubt about that. It's just that we hadn't seen a lot of the drilling that's taken place here in the last six months be those kinds of programs and those kinds of wells, but I'm sure that'll turn. My follow-up, if I could. Sand. If I just do back of the envelope stuff, you guys buy and supply to your customers a great deal of sand. I'm coming up with at least a billion and a half a year in dollars that comes through. Does that all come through your income statement, Mark? Is there a margin to that? Or if I were to take these sand pass-through revenues off your income statement, would that have the appreciable benefit to margins? Am I looking at this right?
Yes, we do buy sand for our customers' account, and that's on the ticket. In a typical market, we would bill that sand with a margin that's designed to recover the cost of the delivery. We do the delivery. We take it to mine. We move it by rail through transloading and essentially arrange the logistics to move it the last mile to the well site. We don't articulate all that cost out, but the margin is designed to recover that cost and put it in line with the other margins that we have across the pumping and other service side of our business. Obviously, what's happening right now is we're not earning a margin on a lot of that business.
In some cases we may, the practical reality when you're negative in North America, particularly on the pressure pumping side, you're not making money on the sand. You could look at it as if right now we're buying sand for our customers' accounts.
Yep.
That's not a sustainable practice. That's a large part of what we're trying to repair. We do believe that the scale of the operation that we have, the amount of sand that we move, the quality and the efficiency of the transloading operation that we provide is a significant value add to our customers. We can make sure that it arrives on time, in quantity. When supplies get tight or logistics get complex, they don't have to worry about working with Halliburton to get it there, and we're never waiting on sand.
I figure if the MLP valuations ever come back, you're going to get a great deal of pressure to spend that off. That's how good you are. Okay, Mark, thank you very much. I appreciate it.
Thank you, Jim.
Thank you. Our next question comes from Sean Meakim with JP Morgan. You may begin.
Hey, good morning.
Morning.
Morning.
You guided the flattish margins next quarter for international, again, the minimal seasonal benefit. Thinking about the first half of 2017, how much of that bottoming comes from the seasonal drop-off in the first quarter versus ongoing budget challenges in some markets, maybe like Latin America? Just trying to think about, does that guidance imply 2017 budgets likely flatter for, say, flat to lower year-over-year, but with that sequential improvement in the back half?
This is Jeff Miller. International business traditionally lags North America by six to nine months. That's just sort of broadly across all of the markets in terms of activity. We're continuing to see, if you look at sort of geographically outside of the resilience in the Middle East, there's been a substantial decline in activity commensurate with the commodities. Certainly Latin America is at a historical low. Asia Pacific is down, in some ways as much as 50% in terms of rig count that we see in the marketplace. I think that that continues into kind of the first part of next year, there's obviously the resetting budgets with the National Oil Companies and a lot of things that conspire to slow that down.
Certainly not clear, but expect consistent with our outlook that middle of next year is where we start to see that repairing.
I think that we don't really have a lot of visibility from customers yet. The first quarter will be down seasonally. It's usually in North Sea and Russia that has the largest impacts. Then to a lesser extent in Latin America, you'll have some delays as NOCs reset their budgets, then begin to let work. I think that the veracity of the once we hit the bottom in international in the early part of next year, the veracity of any recovery is going to be based on what the commodity price outlook is at that point in time.
Got it. Understood. It's definitely still early. Then just one more question on the Permian, if I could. The Permian is very much the focus among the E&Ps today, particularly the Delaware and the Midland. Curious if the recovery and activity is less broad-based than last cycle and more limited to the Permian. How do you we think about competition in that market, mix of wells and customers, how some of that could have an impact on margins and pricing in that basin?
Well, Permian Basin is the most competitive basin in North America today. It's had the majority of the rig adds were in the Permian Basin. Quite a mix of customers that added rigs, doing a variety of things, as we've already talked about. Some vertical wells, some proving up acreage, just a range of activity. Starting from a smaller base in other parts of the country. Are we seeing some pickup? Yes, in the rig count, and that's part of the reason we stay engaged in all parts of the market. I think that Permian from an activity standpoint will be busy. Again, it's a highly supplied marketplace as well.
Maybe some of those other areas could provide opportunities for you all, given how much competition has likely left those lower activity basins.
Yeah. Well, our strategy's clear that we want to be in the business and we want to be in the business in a full service way in all of the markets.
Great. Thank you.
Thank you. Our next question is from Dan Boyd with BMO Capital Markets. You may begin.
Hi, thanks. I'd like to follow up on one of the questions earlier from Jim. As you think about your logistical network and the infrastructure, I think that's something we all view as one of the key competitive advantages of Halliburton. Can you maybe give us an update on where your infrastructure currently stands? Maybe how much capital was invested in that business, and would you consider different structures to get that off your books in the future?
We're not going to give specifics on the total capital invested or anything like that. I would tell you that we've got transloading capabilities in all of the major basins. We feel like that we've got sufficient capital and resources to make sure that we can service our own business. It was purposely designed in a way that doesn't meet 100% of our needs. That's in talking about how you varialize your business. One of those things has been that we have tried to construct that in a manner that meets a significant portion of our transloading needs, but allows us to also to be able to flex with the market should the need arise. We believe right now that it's an important strategic asset. We're going to continue to hold that. I can't tell you where or if.
It's just one of those things that, like any other portion of our business, we'll continually look at that, look at the returns that we earn off of that business, its relative importance to customers in the market, and make evaluations as we get there.
Okay, thanks. A follow-up is just looking at the Permian and the transloading facilities and basically the sand deliverability infrastructure there. How well utilized is that network, and could that be a limit to activity in the Permian at some point?
Look, I don't see any limitations currently. There are always parts of that chain that we're working on how to improve, how to make better. Ultimately, we're able to overcome those sorts of things pretty consistently. As we've demonstrated in the past, we've led in how we've resolved those types of opportunities in markets. I think to the extent the Permian continues to strengthen, those investments will be made where required.
Okay, thanks.
Thank you.
Thank you. Our next question is from Rob MacKenzie with Iberia Capital. You may begin.
Thank you, guys. I had a follow-up question on the margin front from earlier. I guess my question is, with the lean cost structure you talked about, variableizing costs where you can, underutilized existing asset base, why would incremental margins only be in the 35%-40% range? Why shouldn't we be able to expect to see something higher than that?
At some point, they will go higher. It's usually a progression. Right now, coming off the bottom, we're fighting every day for some level of pricing and trying to get crews above water. When you have crews below water, it creates some level of stress on your incrementals, and it's not consistent. A crew one month could be doing fine. The next month, based on customer choices about working or downtime, maintenance, whatever else, could go underwater. Until you get everybody consistently above water, the incrementals stay a little bit choppy. They moved up from what we were expecting. As a result of the utilization that we're getting, we're now sort of seeing in that 35%-40%, and they can go higher from there.
Historically, we would see a trough, the trough in rigs was followed by a trough in margins. In my view, we've actually accelerated that and a lot of that on the back of the cost reductions and the structural cost moves that we've made, which we've always said we wouldn't see the real benefit of those until we saw some sort of bottoming. We've seen that. In some ways, we're moving more quickly than we'd expected.
Yeah.
Yeah, I would just add one more thing, it continues to be the comment was on incremental margins for the fourth quarter for North America. As we said earlier, we're continuing to factor in some downtime over the holidays, which means your revenues go away, but your costs don't.
Right.
That clearly has an impact on your incremental margins at that point in time. All of that being said, as we said in the call, we said in the release, things are getting better in North America. I think if you take something away from this call, it's that thought, not the sort of tactical things we have to do day to day to work our way through the quarter.
Great. Thanks. That's a good answer, guys. My follow-up question comes back to the, I guess, the frac calendar, if you will. What are you seeing, if anything, in terms of larger job requests from your clients, either term work, multi-well pads, versus kind of the real very short-term spot work we've seen? Where does that stand in terms of the evolution of backlog for you guys?
Yeah. Well, we're obviously seeing some increase in that in terms of both terms and size. Obviously, we're not going to comment on strategy at this point in time. We manage through kind of the optionality and manage in our entire portfolio.
Yeah, I would just say, listen, our customers are smart. They see 2017 shaping up to be better. They're going to try to lock in as much time and price as they can at this point in time. It's up to us to navigate our way through those requests and make sure that we are not only there to service them with the equipment they need, but that we are there with a price that gives us the kind of returns we need to satisfy our own shareholders. It's going to be a give and take, but there's certainly some of that going on right now.
Great. Thank you, guys.
Thank you. At this time, I'd like to turn the call back over to Jeff Miller for closing remarks.
Thank you, Shannon. I'd like to wrap up the call with just a couple of key points. First, North America unconventional market has, as predicted, recovered first and should continue to strengthen in a plus $50 oil price environment. Secondly, Halliburton's strategy is directly pointed at the most important part of the market in collaborating and engineering solutions to maximize asset value for our customers. This, along with our customer relationships, geographic footprint, and service quality, positions Halliburton to outperform in the recovery. Thank you, and I look forward to speaking with you next quarter.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone have a great day.