Lance Loeffler - VP, IR Dave Lesar - CEO Mark McCollum - CFO Jeff Miller - President

James West - Evercore ISI Jud Bailey - Wells Fargo Scott Gruber - Citigroup Angie Sedita - UBS Bill Herbert - Simmons David Anderson - Barclays Kurt Hallead - RBC Capital Jim Wicklund - Credit Suisse Sean Meakim - JP Morgan Dan Boyd - BMO Capital Markets Rob Mackenzie - Iberia Capital

Good day, ladies and gentlemen, and 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. [Operator instructions] 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, and 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 31, 2015, Form 10-Q for the quarter ended June 30, 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. Now, this has been a historic down cycle for the industry and it’s 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 out-executed even the very high expectations we placed 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 activities starting to pick-up as we start the fourth quarter. We continue to aggressively implement our structural cost reductions announced in our first quarter call, and we have met our goal. On a monthly basis, we have already achieved the run rate of a $1 billion of cost savings annually. We also generated over a $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. And 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 our future drilling plans, and I believe they will approach the recovery with a rational, methodical response in activity based on commodity price fluctuations. Now, 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 downturns. 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 would rather just wait till next year to start drilling. And I believe we will see a lot of that mentality in the fourth quarter. But that being said, it does not change our view that things are getting better for us and our customers. Now, let’s turn internationally. I like where our market share is today in the international markets, and 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 and pricing headwinds during the quarter, but in anticipation of those forces, we aggressively managed our cost. 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 to 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 so 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. However, we’re confident in our ability to navigate through this cycle and in our continued focus on unconventional mature fields in deepwater markets. As we have said before, unconventional, particularly those in North America are leading their 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 cost. And 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’re 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 there role of swing producer in global oil production. Because of this shift away from production discipline, which was historically created by OPEC, our industry will likely experience shorter commodity price cycles going forward. So, we see the future market as a combination of shorter cycles and range-bound commodity prices. In that environment, it is imperative that we returns-focused companies like Halliburton be more asset-light. Having an organization, structuring 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 is then in prioritizing returns over margins and revenue, and that philosophy will continue. Now don’t get me wrong. We are always focused on improving margins. But 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. And I have full confidence we’re 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. And I am confident that 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 the 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 a $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 the $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 the decline in operating income of 4%. The decrease through 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 a $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 a 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. However, the difference this quarter from the rate we anticipated was largely due to an adjustment reflecting the beneficial use of an Argentinean 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 day sales outstanding and the receipt of a series of tax refunds. Capital expenditures for the year are still expected to be approximately $850 million. Now, 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% to 40%. In our international business, we believe the typical seasonal uptick in year in software and products 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. Now, I’ll turn the call over to Jeff for the operational update. Jeff?

Thank you, Mark and 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 and our organization has delivered on service quality, has delivered on cost savings and has absolutely executed on our value preposition, collaborating and engineering solutions to maximize asset value for our customers. The result of this execution was improved margins and repeat business. So, 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 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’m convinced this is the winning formula. In pressure pumping, we estimate that the U.S. active fleet, I emphasize ‘active’ grew to over $7 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. And as I said last quarter, this is the first step towards a balanced market for the industry’s available fleet. And while we know the industry has additional horsepower on the sidelines that could come into the market, we also know that this additional equipment require substantial maintenance to be put back to work, and will require adequate price increases to justify its return. So, as we look ahead, we expect pricing to work its way through a couple of predicable 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 two is when we see equipment requiring significant investment returning to the market. I expect that this will require a 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 plateau. Market share is valuable and that’s why we build it in the downturn. I think Dave was crystal clear that our target is leading returns, and we have not forgotten that. High market share gives us choice in the recovery to work with the most efficient customers and 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 had never been higher for us to help maximize the value of their assets. And this is exactly what we’re doing. So, 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 the robust drilling and completion plan in place, the customer started to minimize completion damage during flowback and maximize overall recovery. Through the use of our CALIBR 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 has 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 customers drivers and work with them to develop a unique solution to make their goals. CALIBR 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 surgi-squeeze 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 the customer, the engineered solution that maximizes our asset value. In Brazil, we worked 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 multiyear 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 why we get things done and why we are the execution Company. To sum up, I’ve walked through our value proposition and action, and it’s equally effective in all of our strategic markets unconventionals, mature fields and deepwater. 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, and 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. And 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 side execution, all geared to respond quickly to deliver returns. So, to me, no matter what market is handed to us, Halliburton is well-positioned, and 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. [Operator Instructions] Our first question is from James West with Evercore ISI. You may begin.

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, and maybe it’s not in the Permian but maybe some of the basins where equipment has migrated out of?

Pricing is still, yes, I’ll describe it overall as a brawl. As I said, we’re always pushing on pricing. We’re seeing small increases in different basins, but where we’re most focused around those customers with whom to collaborate the best. And 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.

And then maybe a follow-up on that, so I guess your strategy for unstacking equipment at this point, you suggested it’s more of a conversation about returns on the assets. That 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, I mean the equipment’s got to make returns. And in my view this does require step up in price. And so for that reason, we don’t have current plans to have or start to the market. I would expect the next round of investment broadly to drive better discipline related to returns.

Thank you. Our next question is from Jud Bailey with Wells Fargo. You may begin.

A question for Dave or Jeff, I was hoping -- could you expand maybe Dave on your comments, in your prepared comments, on the need to be asset light, I think you said in the context of a shorter cycle that you envisioned, does this reflect any type of change in how you are going to run the business or strategy or how you think about investing in the business given your comments?

We’re focused on everything that drives returns. And in my view, the shorter cycles are really closer to our value preposition, which is execution and the last mile. And so for example, it’s not vertical integration for the sake of integration and it’s not -- and it’s variabilizing everything that makes sense to variabilizing our business. So, then 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 that drive that velocity in all parts of our business. And we clearly believe this is how we drive leading industry returns.

And I guess my follow-up is the guidance for North America in the fourth quarters is pretty straight forward. I was wondering do you -- what kind of visibility you may have in terms of calendar for the first quarter, early 2017. Obviously it will be dependent on where oil prices shake out and what OPEC ultimately does. It sounds like you’ve got some customers who are starting to lineup work for 2017 at this point. And I was wondering if you could perhaps give any color to that effect.

Well, we see -- as we talked about Q4, I mean 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. But again that part of the market is not as clear at this point in time. So, we are going to manage our cost and manage our businesses. We look at that to keep the structural cost and savings in place and be absolutely positioned for when the recovery happens or where that happens.

This is Mark. I think our general view is that Q1 is going to be better, right. And the customers are engaging but the amount -- 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. So, we think we’re clearly on a path for recovery.

Thank you. Our next is from Scott Gruber with Citigroup. Your may begin. Scott Gruber : So, I was down in the Permian about a month ago and met with a collection of operators, and everyone just was discussing more sand per well and longer laterals, two trends that everyone has been discussing for a while. The trend that stuck out to me and which appears less well appreciated is the trend towards more frack stages per well. A couple of operators were discussing shifting towards fully 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?

Look, we are seeing a move towards shorter spacing on the stages which ultimately drives more stages, and this will drive more service intensity for us. More stages means more plugs, means more perfs, earns more sand. So, 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. And so, 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 sub surface inside, and ultimately how to make a better well.

And just generally, are you seeing operators outside of the Permian squeeze the spacing as well as is this just a Permian phenomenon?

I would say that what’s right is what’s right for the rock. And I think you’re seeing that moving into Permian basin, probably less so in another places, so constantly trying new ways to again get more sand in the right place as opposed to just more sand.

Thank you. Our next question is from Angie Sedita with UBS. You may begin. Angie Sedita : I echo the congrats on impressive quarter given market conditions and 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 for Mark is do you -- we are 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’ve never finished in terms of reviewing our overall structural costs. Jeff made the comment earlier about variabalizing costs. And I think there are some things that we haven’t necessarily always thought of as structural. They are -- they would be variable in a definition of how we would typically look at them. But when we talk about variabalizing those, we’re talking about possibly looking at do lease versus buy; do we turn the 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. So, I think that we’re going to go into next year. 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. And even planning flat requires the organization to continue to really focus on what can we do from a continuous improvement standpoint to continue to drive that cost. I believe you’re never done, and we’re going to continue to go forward.

So 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 currently deployed fleet at full utilization.

Yes. What I would do is let’s go back to kind of a margin progression for the business and in my view it’s a path back rather than a dramatic job. And so, as we said, certain things have to happen around equipment tightening and attrition and it starts with making positive operating income then returning the cost to 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 the formula that we know.

We’re definitely going to need some price to back toward the historic margins that we’ve had in the past and historic returns. But the first order of business is to get capacity tightened up in the market. We believe the activity levels in the Permian and others all are serving to work equip harder, it’s going to tighten up equipment faster and we’re starting to see price against the edges and we’ll continue to drive that forward as we hold the line of cost and it’s -- we’re going to get there. The model is the same and we’ve just got to execute.

And so, 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. I mean 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. And hopefully we’re going to be pushing this hard as we can to get back to 20% as quick as we can.

Thank you. Our next question is from Bill Herbert with Simmons. You may begin.

So, Mark, a quick question with regard to the guidance for the fourth quarter and sensibly, you seem to be a little bit conservative about North American top line and sort of in line with the rig count obviously [ph] expectation. But 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 in Halliburton’s North American top line outpace the rig count in Q4?

Let me take that one. I think as Jeff said, the frac calendar is full but my 20 years of being -- 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. And it doesn’t always come true that we utilize that work, and that calendar can get dumped pretty aggressively toward the end of the year, toward the end of the fourth quarter. So, 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. And my experience has been some years it happens but most years they start to pull things off the calendar as the holidays get there. And you’ve got the added I think dimension this year, 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 run them out on a pad and run them for 60, 80, 90, 100 days and get the efficiencies from them. So, 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.

And in line with…

Bill, I was just going to say the follow-on, you also recognize we saw 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. And so, it may not necessarily follow directly with the rig count to get out….

And then Dave, in line with your pretty stark but realistic commentary about deepwater, I’m just curious as to how you’re thinking about your global deepwater footprint right now and whether that represents another significant round of call it right-sizing for Halliburton in terms of cost cutting reductions?

Bill, let me let Jeff handle that one because he’s dealing with it every day.

We like our footprint around the world and I think deepwater certainly has important role to play. It’s clearly the most stressed today and 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 add backs. 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. And we know how to flex the cost around those facilities but I will tell you keeping that footprint in place is something we will do. Again, I have described our value preposition around last mile execution. That means you have to be present to win, and we plan to be present.

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 I was going to ask you there. I was wondering if you could expand a bit on the increased utilization in North America. Is that just continuing to squeeze up a wide space, is it dropping certain customers as far 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 concerning your saying margins are now taking a priority over market share.

Well, I guess we’re in a unique point in the market right now where we are setting up with -- we’ve got choice because we have market share. And so, 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 is mutually beneficial for both of us. So, 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. And as I’ve said, we’re not going to add equipment until we see clearly better returns, and I think that’s going to be prohibited to others to add equipment until the price moves where it needs to be.

Clearly, our utilization has gone up quite dramatically as a part of this process and that was a large part of what helped the margins this quarter; we’re going to continue to work that formula here for the next quarter or so.

Okay. And just a follow-up question; one of the other things we hear from E&Ps now there’s been a talk about moving more to slickwater fracks. Just wondering how that could potentially change kind of revenue and margin potential on your pressure pumping business as we move ahead to next year.

I mean slickwater 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 slickwater. So, we’re preferentially positioned around that. And I would also go further to say that today’s market is the mix bag of frac designs, So, we still see quite a bit of gel, some hybrid and yes certainly slickwater. But when I think about the longer-term future, where does it go, the key point is controlling the frac in our view. And that’s why we study chemistry. And 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’re that focused on making better wells.

It’s always important to remember that Halliburton operates in every basin across the whole of North America. And what’s happening just in the Midland or Delaware, in the Permian isn’t -- every basin, every rock is different. And so, we go to market where the customer needs to get the best well in those markets. And so, it will be -- we’re uniquely positioned to get the best out of our equipment and of our projects.

Thank you. Our next question comes from Kurt Hallead with RBC Capital. You may begin.

Dave, a question for you, you mentioned the shift in the strategy to go asset light. By definition, frac is very asset intensive. So, I was hoping you give a little bit more color around the context of asset light.

I think as we’ve said, it’s not a shift in strategy; it’s a continuation of a strategy where more continuation of a philosophy is that we’re returns driven first. And to the extent we can get by with less assets, we can variablize our asset base, then we are going to continue to do that and that’s really all it means. So, I don’t want anybody to read too much into this. It’s just a prioritization of returns and when you’re 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. And that’s really where we are.

Got it. And then, follow-up on the comment about potentially being willing to get some share for margins, was that U.S. market specific?

We take a look at every basin, every customer, every geography every day and 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 a great footprint that we have and allows us the optionality of making those decisions each and every day.

Thank you. Our next question is from Jim Wicklund with Credit Suisse. You may begin.

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 sponsor 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 the drill complex wells. Has the move so for off the bottom been a rig count that is not clearly beneficial to you guys and is that one of the issues that will be solved as we get into 2017 and more established companies pick up drilling?

Jim, the rigs that we’re seeing, as you describe them are probably less service intensive and they have also tended to be less about big new capital programs and more around -- 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 tough that this comes right over the next period of time because, again where we can do engage is when they start to make the bigger decisions around how to design fracs where we are 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. And again part of being, as Dave said around asset light is not -- is velocity as much as it is anything else. And so, we’re drilling long horizontals and we’re full on. That’s where we absolutely are best.

Yes. I have no doubt about that, it’s just that we haven’t seen a lot of the drilling that’s taken place here in the last six months be those kind 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 and coming out with at least $1.5 billion a year of it, and dollars that comes through, does that all come through your income statement, Mark, and 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?

So, yes, we do buy sand for our customers account and that that’s on the ticket. We bill -- we in a typical market, we would bill that sand with the 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 then arrange logistics to move the last mile to the well site. So, 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, I mean in some cases we may. But the practical reality when you’re negative in North America and particularly on the pressure pumping side, you’re not making money on the sand. I mean, you can look at it as right now we’re buying sand for our customers account. And that’s not a sustainable practice. And so that’s a large part of what we’re trying to repair. But, we do believe that our ability -- the scale of the operation that we have, the amount of sand that we move, the quality and the efficiency of the transloading operation and we provide a significant value add to our customers. We can make sure that arise on time and quantity. When the supplies get tight, our 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 MLP valuations ever come back, you’re going to get a great deal of pressure to spin that off, that’s how good you are. Okay, Mark. Thank you very much. I appreciate it.

Thank you. Our next question comes from Sean Meakim with JP Morgan. You may begin.

You guided the flattish margins next quarter for international, given the minimal seasonal benefit. Thinking about the first half of ‘17, 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 or say flat to lower year-over-year but with that sequential improvement in the back half?

The international business traditionally lags North America by six to nine months. So, that’s just sort of broadly across all of the markets in terms of activity. And we’re continuing to see and if you look at sort of geographically outside of the resilience in the Middle East business, there’s been a substantial decline in activity commensurate with the commodities. And certainly Latin America’s had historical low; Asia Pacific is down in some ways as much as 50% in terms of rig count that we see in the marketplace. And so, and I think that that continues into kind of the first part of next year and there is obviously the resetting budgets with the national oil companies and a lot of things that conspire to slow that down. So certainly not clear but we expect consistent with sort of our outlook that middle of next year’s 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 as usually in North Sea and Russia that has the largest impacts and then to a lesser extent in Latin America you’ll have some delays as NOCs reset their budgets and then begin to work. But I think that veracity of the -- once we hit the bottom in international in early part of the next year, the veracity of any recovery is going to be based on what the commodity price outlook gives at that point in time.

Got it, understood, it’s that it’s still early. And 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. Just curious if the recovery in activity is less broad based than last cycle and more limited to the Permian? Just how do we think about competition in that market, mix of wells, and customers and how some of that could have an impact on margins and pricing in that basin?

Permian basin is the most competitive basin in North America today, 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 and other parts of the country, are we seeing some pick up, yes in the rig count and that’s part of the reason we stay engaged in all parts of the market. So, I think that Permian from an activity standpoint will be busy but again, it’s a highly supplied marketplace as well.

So, maybe some of those other areas could provide opportunities for you all, given how much competition is likely left with those lower activity basins?

Yes. I mean, our strategy is 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.

Thank you. Our next question is from Dan Boyd with BMO Capital Markets. You may begin.

I’d like to follow up on one of the questions earlier from Jim. And 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 of your book in the future?

So, we’re not going to give specifics on the total capital invested or anything like that. But I would tell you that we’ve got transloading capabilities in all of the major basins that 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 I’m talking about how you variablize 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 that allows us to also to be able to flex with the market, should the need arise. And so, we believe right now that it’s an important strategic asset. We’re going to continue to hold that but, I can’t tell you where or if. It’s just one of those things that like any other portion of our business, we will 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.

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 -- 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, but ultimately we’re able to overcome those sorts of things pretty consistently and as we’ve demonstrated in the past, we’ve led and how we’ve resolved those types of opportunities in market so. And I think to the extent the Permian continues to strengthen, those investments will be made where required.

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, is with the lean cost structure you talked about, variabalizing cost where you can underutilized existing asset base, why would incremental margins only be in the 35% to 40% range; why shouldn’t we be able to expect to see something higher than that?

At some point, they will go higher. And it’s usually a progression, right now coming off of bottom, there is still -- 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. Crews -- crew one month could be doing fine, the next month, based on customer choices about working or downtime, maintenance whatever else could go under water. So, until you get everybody consistently above water, the incrementals stay a little bit choppy, but they’ve moved up from what we were expecting. And as a result of the utilization we’re getting, we’re now sort of seeing in that 35% to 40% and making go higher from there.

Historically, we would see a trough following, the trough in rigs was followed by a trough in margins. And so 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 bottom. And so, we’re seeing that. And so in some ways, we’re moving more quickly than we would expect it.

Yes. And I would just add one more thing and it continues to be -- the comment was on incremental margins for the fourth quarter for North America. And 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, and that clearly has an impact on your incremental margins at that point in time. But all of that being said and as we said in the call, we said in the release, things are getting better in North America. And 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.

That’s a good answer, guys. And my follow-up question comes back to 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 structured spot work we’ve seen; where does that stand in terms of evolution of backlog for you guys?

Yes. 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, but we manage through kind of the optionality and manage our entire portfolio.

I would just say, listen, our customers are smart, they see 2017 shaping up to be better and they’re going to try to lock in as much time and price as they can at this point in time. And it’s up to us to navigate our way through those requests and make sure that we -- we’re not only there to service them with the equipment they need but we’re there with a price that gives us the kind of returns we need to satisfy our own shareholders. So, it’s going to be a give-and-take but there’s certainly some of that going on right now.

Thank you. At this time, I’d like to turn the call back over to Jeff Miller for closing remarks.

Thank you, Shannon. And I’d like wrap up the call with just a couple of key points. First, North America unconventional market has a predicted recovered, first, and should continue to strengthen in a plus $50 oil price environment. Secondly, Halliburton strategy is directly pointed at the most important part of the market and collaborating and engineering solutions to maximize asset value for our customers. This along with our customer relationships, geographic footprint and service quality positions Halliburton outperform in the recovery. Now, thank you and I look forward to speaking with you next quarter.

Ladies and gentleman, thank you for participating in today’s conference. This does conclude today’s program. You may all disconnect. Everyone, have a great day.