哈里伯頓 (HAL) 2016 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halliburton second-quarter 2016 earnings conference call. (Operator Instructions) As a reminder, this call may be 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 Halliburton second-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 March 31, 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 include non-GAAP financial measures and, unless otherwise noted in our discussion today, we will be excluding the Baker Hughes termination fee and the impact of impairment and several other charges. Additional details and reconciliation to the most directly comparable GAAP financial measures are included in our second-quarter press release, which can be found on our website.

Now I will turn the call over to Dave.

Thank you, Lance, and good morning to everyone. Our second-quarter results showed great resilience in the face of a very challenging environment, which included declining rig activity and even more pricing headwinds. Our total company revenue declined only 9% sequentially compared to the 19% decline in the global rig count. And our North American revenue was down 15% from the prior quarter, significantly outperforming the 23% decline in the average US rig count.

However, despite these continuing headwinds, based on the recent improvements to North American activity, I believe that the second quarter will mark the trough for our earnings. Now we are at a dynamic point in the cycle and I'm not going to waste the limited time we have with you on the call this morning discussing things like the macroeconomics, the worldwide demand, the general economy, or commodity prices. There are many public sources out there where you can get this data, including our customers, because that is the world that they live in every day.

What I want to talk about today is the world that we know best. Now conventional wisdom coming out of the first quarter was that the rig count would continue to drop. We said we saw North America differently and were the first to call a bottom for the rig count. This is precisely what happened.

So let's talk about the reality of today's North America market. I can summarize this market in one sentence: Today our customers are thinking about growing their business again, rather than being focused on survival. There are two distinct factors at work in North America, psychological and economic, and I think it is critical to understand them both.

Now you haven't heard me talk about the psychology of North American producers before, but given what has happened to many of our customers in the last 18 months, I think it is an important point to understand. I spent a large amount of time with customers late in the quarter taking their pulse and I can tell you there is a growing survivor mentality out there. And you can't underestimate the positive change in attitude that we are seeing in our North American customers. There is a spring in their step that I didn't see earlier in the year and in almost every case they are talking about adding rigs, buying assets, or doing something value-accretive. In short, they are getting back to business.

And the psychological factors are getting better. Oil reaching $50 per barrel, even for a brief time, was a critical emotional milestone for our customers, as was being able to buy a strip above $50 per barrel. But maybe it can be summed up best by one customer who told me: Dave, it's actually a light at the end of the tunnel and not an oncoming train. So to borrow a Keynesian economic term, the animal spirits are back in North America.

But also understanding the economic reality in North America is equally important. Pricing has helped cash flow, but not enough. Hedges rolling off have created cash flow uncertainty. Balance sheet repair is still critical and many customers are looking at severe declines in production, as many of them have drilled few wells in the last 18 months.

And while there are many customers that have adequate liquidity, there is also a large segment evaluating how to access capital. This evaluation is around whether to do dilutive equity deals, accessing the high-yield markets, looking at reserve base lending, or partnering with private equity. But the important point is they are back in business.

Now our North America customer management teams are great to work with. They are creative, adaptive, and increasingly confident and I believe they will find the solutions best tailored for their companies. This is also a smart group and they see today's looming supply shortfall and know that US unconventionals will likely be the first and deepest beneficiary of growing supply shortages. And you can be sure they want to reap some of that benefit.

So let's talk about how the cycle is starting to stack up and how this coming up cycle will play out. Now, obviously, the last two years has been a period of significant underinvestment where global CapEx has been reduced by nearly $400 billion. As a result, the industry will have to find a lot of new barrels in the next five years.

You can choose your own energy supply expert, and there are many of them out there, but most agree we will need between 18 million and 22 million barrels per day of new production by 2021. Meaning we have to find nearly two Saudi Arabia's worth of production in the next five years.

To achieve this production goal, we believe there will need to be structural changes that have to happen. It clearly starts with a supportive commodity price, and we are not there yet today, but prices will have to get there soon or the supply challenges will be even greater.

Industry balance sheets will need to be repaired. The industry will need to replenish experienced lost to retirement and cutbacks. We will have to find sustainable ways to deepen the relationships between operators and service companies, collaborating to integrate better, eliminate duplication, and drive down delivery costs.

Finally, producers will have to accept the reality of service company economics. Some of the efficiency gains we have made with our customers are, in fact, sustainable and will continue, but others, including deep, uneconomic pricing cuts, are unsustainable and will have to be reversed.

In this environment, we are confident that North America will recover the fastest. The North America market has turned and we expect to see a continued modest uptick in the US rig count during the second half of the year and becoming more meaningful as we go into 2017.

Now that we have seen the floor in activity levels, we expect revenue to increase based on higher utilization rates. And as we have said consistently, rig count stabilization is the first step on the road to margin repair. Jeff will discuss that in a few minutes.

Current service pricing in North America is unsustainable. We are in an environment where service providers are unable to meet their cost of capital and many are struggling to recover even their cash costs.

Historically, as we reach the bottom, the downward momentum on pricing creates a headwind and margin repair tends to lag activity recovery by a quarter or so. To break this typical cycle, we've made structural changes to our delivery platform, eliminating management layers and consolidating roles and locations. As a result of these savings, we are confident that North America margins can begin to recover in the third quarter.

When this downturn started, we said that we were entering it from a position of strength in all of our markets. Since that time, we have executed our downturn playbook and have continuously outperformed the market, both in North America as well as the Eastern Hemisphere, gaining market share in both.

So to summarize, the market has played out as we predicted and our strategy is working. North America has turned, and with our market share increased during the downturn, we believe we are the best-positioned company. During the coming recovery, we plan to scale-up our delivery platform by addressing our product line building blocks one at a time through a combination of organic growth and selective acquisitions.

With that, let me turn the call over to Mark and Jeff to cover our financial and operational results. Mark?

Thanks, Dave, and good morning, everyone. Let me start with a summary of our second-quarter results compared to our first-quarter results.

Total company revenue for the quarter was $3.8 billion, which declined 9% compared to a 19% decline in the worldwide rig count. Total company operating income declined 72%, primarily due to the continued decline in global activity and pricing, as well as the reintroduction of depreciation expense for our previously held-for-sale assets.

Moving to our region results, North America revenue declined 15% with margins moving down to an operating loss of 8%. The primary drivers were the impact of reduced pricing and activity in our stimulation, wireline, and drilling product lines.

In Latin America, revenue declined 12% and operating income declined 54% as a result of reduced activity levels in Brazil, Mexico, and Colombia, and by our decision to curtail our activity in Venezuela. Rig activity in both Brazil and Mexico is at a 20-year low, while Venezuela continues to experience significant political and economic turmoil.

Turning to Middle East/Asia, revenue declined 3% while operating income declined 22%. We saw increased activity in Kuwait and fairly consistent activity in Saudi Arabia. However, we also began to experience pricing pressure across the region and activity levels declined in Iraq, Australia, and Indonesia.

In Europe/Africa/CIS, second-quarter revenue increased 2% and operating income increased 12% as a result of the seasonal recovery of activity in the North Sea and Russia. Our corporate and other expense for the second quarter totaled $60 million and we expect third-quarter expense to come in at similar levels.

We recorded a tax benefit for the second quarter of approximately $6 million. Based upon our current outlook for the third quarter, we anticipate that our effective tax rate will be approximately 50%. This unusual rate results from having tax losses in the US that are then offset by taxable income in the foreign jurisdictions with lower statutory rates.

During the second quarter we had several special charges that we need to highlight. First, as we've previously disclosed, we recognized the $3.5 billion termination fee associated with the Baker Hughes transaction. We also recognized pretax restructuring and other charges of $423 million. These charges consist primarily of severance cost and asset impairments as we continue to adjust our cost structure and footprint to the current operating environment.

The largest single item in that charge was a fair market value adjustment required by accounting rules for exchanging $200 million of our Venezuela receivable for an interest-bearing promissory note. This instrument provides a more defined schedule around the timing of payments, while generating a return while we await payment. There is an immediate expense because accounting rules require that these notes be revalued to their current trading value, even if you intend to hold them to maturity.

Our current intent is to hold them to maturity and we expect to collect 100% of the principal. As such, the notes will accrete back to their par value as they mature over the next few years.

All of these adjustments are tax deductible, but the tax benefit we recorded also includes the impact of removing our accounting assertion while permanently reinvesting our foreign earnings and some adjustments related to the carryback of our now-sizable US NOL. The NOL carry back will provide us with a significant cash flow benefit later this year.

Speaking of cash flow, this quarter was particularly noisy because of the termination of the Baker Hughes deal and continued restructuring work we are doing. When the smoke clears from the unusual items, however, cash flow from operations was slightly positive and we closed the quarter with $3.1 billion in cash and equivalents.

Over our history, it's not unusual for our annual cash flow to be backend-loaded in the year and 2016 is no exception. We continue to commit to living within our cash flows during this challenging environment and improving earnings and a number of working capital initiatives that we are implementing should get us ultimately to breakeven for the year. 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 third quarter. In North America, the US land rig count is already up 5% sequentially on average and is expected to improve modestly over the remainder of the third quarter. We anticipate revenue will outperform the rig count by several hundred basis points and that margins will improve by 100 to 200 basis points as a result of our cost control initiatives and better utilization.

In Latin America, we are anticipating a midteens percentage decline in revenue with margins moving down to the low single digits. Although we may see some end-of-year sales, Latin America is expected to remain our most challenged region throughout the international down cycle and we do not expect to see a fundamental improvement this year.

Finally, third-quarter Eastern Hemisphere revenue is expected to be down modestly, low single digits, due to declining activity and continued pricing headwinds. Looking ahead, we anticipate Eastern Hemisphere activity to decline over the balance of the year. However, we expect margins to remain flat in the third quarter as they also benefit from our cost control initiatives.

Now I will turn the call over to Jeff for the operational update. Jeff?

Thank you, Mark, and good morning, everyone. Let me start today with a headline: 900 is the new 2,000 for US rig activity. What do I mean by that? I believe it will only take 900 rigs to consume all of the horsepower available in the market.

Why? Well, we know the North America market best and we are in every single part of that market. What is clear to us is that the increases in rig efficiency, lateral length, and sand per well create a compounding effect that consumes increasingly more horsepower per rig.

In addition, we watch the effect of the downturn on North America service capacity every day in every basin. We have seen the attrition of equipment, people, and companies. So let me take these in order.

First, horsepower attrition continues due to scrapping and cannibalization. We believe up to 4 million horsepower, and maybe even more, has been permanently removed from the market, representing about 20% of the horsepower capacity reported at the peak. And more is permanently impaired each day.

Industry headcount reductions continue and many of these people are leaving the industry. Finally, company bankruptcies and consolidations also work to accelerate equipment attrition.

Now I want to address what we do as we scrape along the bottom and look ahead to the recovery. The steps are: must be present to win. And we are. We are present in every market. Second is reduce structural cost. We're doing it. Third, increase utilization. We are positioned for it. And, finally, get pricing help. This happens when utilization increases.

To be ready for the recovery, we played offense. First, we actively protected our market position with key customers, kept the majority of our fleet deployed, and delivered fantastic service quality. Despite absorbing the pain of pricing reaching unsustainable levels, we made a strategic decision to stay in every market and keep crews running. In spite of the nearly 80% decline in rig count, our stage count only declined 33%.

So here's what we're doing now. We preserved idle equipment outside of our field locations so it doesn't get cannibalized. It's clear to me that it will be cheaper to reactivate our cold-stacked equipment than to put capital into cannibalized horsepower. This means we are best positioned to more quickly get back to work in the market recovery and are prepared to activate equipment when we see economic opportunities to do so.

In terms of structural cost control, we are making significant progress towards reducing our annual cost structure by $1 billion. We have reduced headcount and consolidated facilities in every region. At the end of the second quarter, we are about halfway there, both internationally and in North America. We anticipate the remaining savings will come in the second half of the year and we'll reach the $1 billion run rate cost savings as we go in to 2017.

The next step is increased utilization. We know our platform is most effective when it's fully utilized, so job one is to fill the whitespace in the calendar. This is why we work with customers to best utilize our platform, in turn helping our customers produce at the lowest cost per BOE.

Throughout the downturn, our superior delivery platform, which is our value proposition -- our people, processes, and equipment -- results in a margin gap to nearly every competitor. And we expect to maintain that advantage in the recovery.

The last step will be the return of pricing. Price negotiations have been a barroom brawl. In certain situations, as we've seen signs of recovery, we have elected to walk away from money-losing jobs in recent months. We've been reviewing every contract and program, down to individual wells, on a pad-by-pad basis, including opportunities for pass-through and cost-related pricing and surcharge.

It's a tough market, but we believe pricing will recover as activity increases. And when we have these four things, we are confident our North America margins will return to double digits.

But beyond North America land, our key focus areas are unconventionals, mature fields, and deepwater, and I am pleased with how we are executing around the world. Though they may be limited, we are working closely with our customers to unlock unconventionals in every region around the world, including recent projects in Abu Dhabi and Argentina.

In the Middle East, we have made significant inroads in our IPN business, taking a market-leading position during the downturn. This reflects the dedication our employees have for understanding their customer needs, identifying solutions, and helping to reduce risks, all while improving efficiency in this uncertain market. This creates a great environment for our collaborative and integrated business model, helping our customers to deliver the lowest cost per barrel of oil.

Though we know deepwater is the most challenged, we are collaborating closely with our customers who are working hard to drive down structural costs and make economic wells. BaraECD is an engineered drilling fluid system that allows us to manage narrow frac gradients while drilling. In addition to reducing overall drilling times, BaraECD has helped break records on rate of penetration and is one of multiple systems that have allowed us to take a number one position in the Gulf of Mexico fluids market.

In Southeast Asia we have a great example of a collaborative effort with a client that optimized a drilling solution, including drill bits and fluids, for an exploration well, reducing the drilling time by 14 days. This cost savings helps to deliver the lowest cost per BOE and is proof that when we work together with our customers and internally, we can provide efficient solutions in any market. The ability to input customer requirements into our drill bit development in short order is what enables us to deliver this collaborative solution.

Collaboration is central to everything we do. Not only do we say it, we do it. A great example is a new resource for customers and partners called iEnergy, available through Landmark. It is an open architecture approach to problem solving.

Now iEnergy was conceived as a community of stakeholders sharing data and building applications. Think of it as our open architecture approach, in contrast to proprietary and closed models in the market today. This is highly indicative of how we collaborate at Halliburton, not only collaborating internally, but collaborating more closely with our customers.

I could go on all day about specific products and services. Let me wrap up with what we do.

Our competitive advantage is this: we collaborate, engineer solutions, and execute to maximize our clients' asset value, which means lower cost and making more barrels. This is why we maintain our global service footprint. We will own the last mile, be present across the globe, and maintain dead focus on service quality.

To sum it up, we like our position. As we expected, the North America unconventional market has responded the fastest, demonstrated by the recent activity pick up. International markets will take more time to rebound, but we are certainly well-positioned for when they do.

I want to close by thanking our employees for maintaining their focus on service quality and executing at every level in this challenging market. Simply put, service quality is central to how we win and retain work. We've seen record low incident rates so far this year and it is important we keep this focus on safety and service quality as the market begins to pick up.

Now I will turn the call over to Dave for closing comments. Dave?

Thank you, Jeff, and let me sum things up. We are prepared for the North American up-cycle. Our approach to the market remains unchanged.

The North American market is turning. It will recover the fastest and Halliburton will be the biggest beneficiary. In the next North America rig cycle, 900 is the new 2,000.

The international markets will follow and we are maintaining our integrated global services footprint, managing costs and continuing to gain share. We are working hard at reducing structural costs. We expect to achieve $1 billion lower run rate going into 2017.

We remain laser-focused on consistent execution, generating superior financial performance, and providing industry-leading shareholder returns. Finally, we expect that the second quarter will be the trough of our earnings and we are confident that Halliburton will be best positioned to outperform in the recovery phase of the cycle.

Now before we open it up for questions, I would like to thank Christian Garcia for his outstanding work over his 20 years at Halliburton and particularly his work as interim CFO during the past 18 months. I very much wish him well in the future.

Now let's open it up for questions.

(Operator Instructions) Scott Gruber, Citigroup.

Yes, good morning. Jeff, as someone who spends an inordinate amount of time on headlines and titles, I really liked your rig count headline. It's a good one.

Thank you.

You stated that about 4 million horsepower has been removed from the North American frac fleet. Can you just provide some color on this figure? How much do you think has been disassembled, cut up, and won't come back? How much has been more of a mothballed state? Overall, where do you think these figures could stand by year-end?

Let me go maybe start with how we get to the 900 is the new 2,000 and then address your question along the way.

Going into the downturn, equilibrium was about 2,000 rigs and 600 frac crews in the US, so a little more than three rigs kept every frac crew busy. Really three factors at play here: first drilling efficiency, then completions intensity, and attrition.

So from a drilling efficiency standpoint, rigs have gotten almost 30% faster, meaning more wells per week per year. So that new ratio is closer to 2 to 2.5 rigs for every crew.

Second is around completions intensity and the jobs have gotten twice as big, meaning more horsepower per crew, almost 20% more. Meaning that the same horsepower that made up 600 crews now only make up 500.

And so then we get to the attrition part of that. There are estimates that range from 3 million to 7 million horsepower that have left the market. We think it's about 4 million. We see that because we're out in the market every day looking at horsepower, but the fact is there is more horsepower that attrits every day just given the type of intensity.

So I think the important point is that the market can tighten maybe faster than you think.

We certainly agree with that point. Quick follow-up. We hear that some of the most dilapidated fleets could require $20 million, $25 million per fleet to reactivate, giving really a full refurb on all the key components as needed.

Is there an argument to be made that pump technology has progressed to the point where it's just simply a better use of capital to build a new fleet than invest $20 million, $25 million to bring a legacy fleet back out?

Scott, certainly our view -- and that is why we kept our equipment the way we have. We segregated it with the -- I describe it as we stacked equipment with the end in mind, so it doesn't take capital to do that. But I do believe that equipment that has not been maintained and has been cannibalized, it would be very difficult to get that economically back into the marketplace.

Great, thanks.

James West, Evercore ISI Group.

Good morning, gentlemen, and congratulations on a well-executed quarter.

Jeff, probably for you; in terms of the North American land market and really just because of the devastation of the industry, and particularly your competition. We see a lot of bottlenecks that are going to appear: labor, working capital, attrition like you just discussed, logistics. Could you maybe comment on what you see from a competitive landscape on where these bottlenecks, these pinch points might occur first or earliest, and then how Halliburton can mitigate these issues relative to the competition that really can't do a whole lot?

Thank you, James. You nailed it; the pinch points will be equipment, sand, and people. We spent time on equipment, but clearly the approach we have taken around equipment is to be best positioned to get that equipment back into the marketplace. So we've talked about that.

From the sand standpoint, it's not the sand as much as it is the logistics. In our view, we are very well-positioned around that having built out our infrastructure over the last several years. We've got sand delivery in every basin and we've got sufficient rail infrastructure to address the logistics part of that.

And then finally around people. We have been careful as we have gone through sort of these restructurings to do our very best anyway to retain experienced people and we have those today. And then don't forget; it was just in 2014 we put 21,000 people onto the payroll and so we know how to do that and we know how to make those people effective. So feel like Halliburton is well-positioned.

Right, I certainly agree. Do you think that some of the market share gains in North America have occurred because of your ability to ramp back up relative to the competition and your customer base understands these bottlenecks and these issues?

Yes, I do. It's part of the flight to quality. As I describe our value proposition, it's our process, people, and equipment, and a big part of that is the reliability of Halliburton to stay. And we have stayed in all of the key markets.

Got it. Thanks, guys.

Jud Bailey, Wells Fargo.

Thanks, good morning. Dave, I was hoping to get a little more color with your thoughts on thinking about North America over the back half of the year. Oil touched $50, as you noted; it's kind of pulled back a little bit, closer to $45 or a little below now.

How does that impact expectations in terms of activity increase in the back half of the year? Is $45 enough? And also, is it sufficient to stabilize the pricing environment? Sounds like pricing is still under pressure.

So just like to get your thoughts on maybe the moving parts in the back half of the year as we think about oil in the mid-$40s.

Let me maybe start and then maybe follow-up. We call it a landing point, which means rigs stop falling, but I think it's important that the -- it's the sentiment that trumps the oil price right now. And based on conversations, they are clearly more positive and constructive than they have been in the past.

But realize we were starting at the worst part of the market; a lot of the worst had been factored into plans, so moving up from what were clearly the worst plans. And I would call it a measured step up as opposed to a boom. So certainly seeing positive things; we think we will be well-positioned for that, whatever shape that recovery takes.

Okay, that's helpful. Thanks. My follow-up is maybe for Mark.

Mark, the margin guidance for North America up I think you said 100, 200 basis points. That implies probably a little bit lower incremental margins than I would've thought given the cost-cutting you guys are doing.

Can you maybe talk a little bit more about the moving parts and thinking about how margins can move up in 3Q and then again in 4Q, given the cost-cutting initiatives?

Clearly, the cost-cutting initiatives are helping us, being able to get out there and address, but I think that the thing you've got to key off of what Jeff was saying that while sentiment has changed, we are still in a very low activity environment.

Our first course of action is to get utilization on the equipment that's out there in the field and to press that quite a bit. There are -- because you can see it in our numbers there are this equipment out there that's ultimately not covering fixed costs. And so we are working on trying to make sure that that equipment, as we get it utilized, is being as efficient as possible to move our margins up.

I think that, as we work through the restructuring, that is going to continue to add margin points on everything. I guess what we are saying is we're not counting on price at this point. The market itself, this utilization and what we are going after; we're fighting for price every single day, but it's still --. It's hand-to-hand combat, as Jeff said, out there and so we are not necessarily baking that into the forward look today.

All right, thanks, guys. I will turn it back.

Angie Sedita, UBS.

Thanks. Good morning, guys. Jeff, I also thought it was very interesting your comments there on the 900 rigs is the new 2,000. And so if you take that one step further, I guess you can conclude that that would imply in your minds that frac utilization would probably be near last cycle peaks of 90% and then expect that another step forward is -- what would that imply on normalized margins this cycle and how you think the pricing will play out this cycle? Is it once we start to reach that 90% utilization or could we see pricing before then?

I think we see -- take the pricing first. That will follow utilization. So as we've described it in the past, we would expect to see utilization begin tighten and at which point you start to see pass-throughs of things and opportunities to improve margins that aren't necessarily price.

The real pricing leverage we actually didn't see in the last cycle. We were getting to that in late 2014 just about the time things slowed down, so a lot of the value creation we are able to accomplish with our platform that's efficient and putting the utilization to it. I think the rest of that was the look forward around margin progression.

Look, I would expect very able to accomplish what we did last time, except probably do better given the fact that we have done some of the heavy lifting around structural costs. So very encouraged about how things would look in the future.

Okay, that's helpful. So you think margins could go back to where they were last cycle, given the cost guiding at a 900 rig count?

Certainly.

Okay, very helpful. Then on the international side, can you -- whatever color you do have; thoughts on when you think we could see the bottom in some of these regions. Also, it was very impressive you saw some market share gains in your international markets. Maybe you could talk about that a little bit.

Typically, international business will trail US behavior by six to nine months and that --. It has historically done that; I don't expect that it's any different, so that means that it is still an absolute brawl in the Eastern Hemisphere. The things that mute that a little bit are the length of the contract terms, which causes it to respond more slowly, and then --. So from -- in my view, margin resilience is really reflecting better visibility that we have because of the longer timeframe and our team, the Halliburton team, just absolutely executing on all points.

And then on the market share gain?

Angie, let me take that one because I think it's important to understand the Eastern Hemisphere is sort of a tale of two customer groups. You've got the NOCs, generally with mature fields, and they are just trying to squeeze more out of their mature fields through their existing infrastructure.

And that part of the business actually has held up pretty well. There is certainly some pricing pressure there. There's certainly some issues with customers trying to lower their cost per BOE.

I think it's the deepwater complex that is the most challenged in this commodity price environment. We clearly are working with our customers, as are all the other contractors, to try to push that cost, that breakeven cost down in the deepwater complex. But where pricing is today, it just doesn't work generally in the deepwater, especially the new deepwater.

So we have been focused on making sure that we get market share gains, even as the market has shrunk, because in the long-term contracting nature of that market, when it does turn back up, you've got those contracts in hand and that market share becomes very sticky at that point in time.

Perfect. Appreciate the color and, of course, my best to Christian as he moves on. Thank you, guys.

Bill Herbert, Simmons.

Good morning. Mark, back to the North America margin question, just trying to understand it better.

If you just focus on the quarterly rate of change, and let's just presume -- I mean you made the prophecy I think with reason that your revenues would markedly outperform the rig count in the third quarter. So just presuming a 10% increase in top line and only a 200 basis point improvement in margin, that implies a 15% incremental at this stage. That just seems to be woefully anemic.

Recognizing the fact that you are underemployed from an asset employment standpoint, is there a negative pricing role that's also being taken into account in the third quarter? Or would you characterize the guidance as conservative?

Bill, I actually am glad you asked the question because I was sitting there thinking there was another point that I didn't get a chance to make on the earlier comment.

One of the things that we are already beginning to see in the marketplace is a little bit of cost inflation. We are seeing it on diesel. We are seeing it in some commodities and things. And so we are already, believe it or not, at this point beginning to fight inflation.

And so during this period of time, this sort of off the bottom here with the slope, the shallow slope that we are on, it makes it challenging. We have got to get capacity utilization before you can really go get price. We are going to push, but it does -- some of the commodities are starting to poke their head up and it's catching us a little bit. And that's part of what's being reflected in there.

Okay. Then, Jeff, with regard to the evolution of your Q2 stage count, how would you characterize -- how did that evolve? I guess the specific question is whether the June exit rate stage count was markedly higher than the Q2 average.

We saw -- it was higher in June, so exit rates were higher than sort of the quarter average, which is reflective of a couple of things: which is modest amount of rig activity, but also we see ducts being worked off. I wouldn't describe ducts as a bow wave, but they are in the mix. And because we are in the market the way we are, we are a beneficiary of that.

How would you describe the frac calendar for the second half of the year? Is it disproportionately weighted towards Q3 and pretty solid and hopeful for Q4, or pretty evenly distributed? How would you characterize your frac calendar right now?

We've always got better visibility sooner than we do further out, but I would describe it as more evenly weighted at this point in time than heavier to Q3.

Thanks very much, guys.

Sean Meakim, JPMorgan.

Good morning. Just thinking about the frac business, Jeff talked about walking away from work in some cases and some of your peers have talked about requiring 20% to 30% higher pricing in order to justify reactivating frac crews. Just curious if you see it the same way.

I was thinking about your thoughts on what will it take for pricing to move higher and how much you would need in order to bring equipment to the market.

Sean, this is Jeff. Look, we're just not going to talk about pricing at this point in time. We continue to look at every crew in terms of what's economic. As we've described before, we care a lot about customer alignment, basin alignment, and customers that are able to consume our platform in a way that helps us and helps them. And so we continue to view it that way.

Okay, fair enough. And then, Mark, you talked about -- in previous discussions you've talked about being opportunistic on some of the upcoming debt maturities. Maybe you pay down some with cash on hand, maybe in some cases you extend depending on what the market is giving you.

Capital market seem fairly amenable today for those with even more challenged balance sheets. Just curious how you're thinking about debt reduction measures or the other potential changes to the capital structure over time.

I think our best opportunity right now is continue to look at maturities as they come due. We've got a $600 million maturity coming up in the back half of the year. Our current intent right now is to make that payment out of our cash flow. We should have the ability to do that; that's a part of our cash flow forecast for the year.

So that's the current intent. We're just going to continue to watch it. We're just continuing to watch it very carefully.

But we've got $3.1 billion of cash on the balance sheet; it's a little more than we need with some of these maturities coming. And you will notice that we have taken the tax hits to be able to move our money around as we need it no matter where it is in the world. So right now current plan is just continuing to naturally delever.

Understood, thanks for your time.

Timna Tanners, Bank of America Merrill Lynch.

Thanks. Good morning, everyone. I was hoping you could provide a little bit more color about some of your international comments. In particular, wanted to take advantage of you're being the first call since Brexit to see if you have any comments on your broader thinking about what that might imply for North Sea operation.

We don't see Brexit alone having a dramatic effect. Though, clearly, like in so many economies around the world, oil and gas is a clear path to help an economy. So in some ways I think that that would be structurally a positive in the UK sector of the North Sea. But immediately no impact.

Okay, great. Then similarly, you talked about a six- to nine-month lag in international operations, but more challenges in Latin America. What do you think we should watch for to think about what would trigger the recovery in that region?

Latin America has terrific reserves. The bottom line is the reserves are there and we've been in some countries in Latin America for 80 years. So I think the positive signs are going to be production.

It's pleasing to see, in Brazil for example, Petrobras clearly back on the business pages today talking about wells that are producing. But I think stability in commodity price is going to have to be one of the first things that helps in Latin America, just given kind of financially where some of our customers are. But, look, it's the kind of market that over time will clearly rebound, clearly rebound.

But it's just going to be later because of the more reliance on oil prices or what makes it so much later? What do you think is going to be that trigger like you said?

Well, I think it's later partly because you have to almost go country by country in terms of some of the disruption that's going on. And so Mexico is working through sort of a market reorganization, along with some other things that have to settle out.

I believe Brazil in terms of sort of the cost of deepwater is always an overhang and how they work through that. And then the other big one being Venezuela. Clearly, a lot of turmoil there and it's very unfortunate, but hope to see resolution over time.

Part of it is just the natural budgeting cycle for many of our NOCs' clients. Their annual budget -- they will have to take their budgets and get it approved by legislative bodies. They are working off a year without significant -- they are not spending and they don't have a lot of cash flow.

And so that means that really, until those budgets are approved, they are not going to be spending. Oftentimes that ends up happening late first quarter or even into the second quarter before everything is approved and so that starts to push out the ramp in spending. Even if they see higher prices, that pushes out the ramp in spending beyond what others might see, whereas in North America they are not relying on legislative bonding. They get out and they spend quickly as soon as they have the cash flow.

Okay, that makes a lot of sense. Thanks so much.

David Anderson, Barclays.

Thanks. Dave, you had talked about the psychology of the E&P getting better. I was just curious; one big part of it has to be the lower breakeven costs that they are seeing. I've been seeing a number of presentations from E&Ps who seem to think that the costs that they have now are basically locked in place.

Just curious how those discussions go. Are they expecting to see oil service inflation? Is this kind of how they are kind of locking in the next couple of years? I'm just wondering about that part of the psychology of the cost side.

Good question, Dave. I think the conversations go like this: hey, we have finally driven service prices down to where we can breakeven, sort of plus-40. My response to that is, yes, for right now; but you are not going to have any service industry take care of you if you think that's where pricing is going to stay. And then you get into sort of a to and fro about what is sustainable.

Jeff hit on some of them. Rig efficiencies sustainable; the speed that we can drill out laterals is sustainable. The bigger jobs and higher production is sustainable, but that doesn't come without a cost.

And so, as I said, these are a great set of customers. They know in their heart of hearts that service prices have to go up. They're going to fight that impact of prices coming up as fast and as long as they can, but the reality is they know they need a viable service industry to be successful in the long run.

So it will be give-and-take. My guess, as we listen to the calls over the next few quarters, is the operators will save they've got them locked and the service companies are going to say we've got to have price increases. And we will end up in the middle somewhere, like we always do.

Okay, so it's a bit of a disconnect now that kind of gets played out over the next year or two, but there is an acknowledgment that the service costs do have to go up at some point though within the --? You think in the heart of hearts that they do acknowledge that there has to be some in there?

In their heart of hearts they have to know that and I believe they do know that.

Great. Thanks, Dave.

Kurt Hallead, RBC.

Good morning. I just wanted to calibrate, see if you guys could calibrate some information for me.

You guys talk about 4 million horsepower reduction in US frac market, so that puts maybe the market about 14 million horsepower, give or take. We have heard, depending on who you want to talk to, maybe about 6 million of that horsepower is currently active in the market. And of that 6 million horsepower you guys talked about a lot of whitespace; that 6 million horsepower may be working 50% of the time.

Does that kind of jive with how you see the market right now or could you help me understand it a little bit better if you think some of those numbers are off?

No, I don't think those numbers are inconsistent with how we view the market and that's why we describe the path back as it starts the utilization of what's there. I think there are barriers to -- a lot of that equipment never makes it back into the market and I do think that unattended equipment almost attrits on its own, particularly with cannibalization. We hear others talking about it, so don't think you're wrong.

So then in the context, as we try to think about the opportunity for margin improvement vis-a-vis pricing, do we need to get back up to 8 million horsepower being active in the market, give or take? Or is it sufficient to get that 6 million horsepower?

We all agree generally on those numbers. Can we get that 6 million horsepower up to 80% utilization and is that sufficient to start to drive some pricing? Any viewpoints on that?

Let me take that one because I think -- again, we are not going to go down any pricing path today. We have a pricing strategy that we are going to follow. We're not going to share it with anybody. It will be sort of a discussion customer by customer.

But I would say one thing is necessary: don't fall into the trap is not all pumping equipment is the same. There are pumping companies out there that have zero utilization today, because they can't find a customer or they're in the wrong basin or their equipment is not qualified to basically sort of pump the formation where they are.

So I think that there is a bifurcation, trifurcation, whatever you want to call it, amongst the pressure pumping companies. And I think a lot of people like the lump everybody together and sort of talk about averages. But I really think it's important to segregate the market into the various basins, the various customers that are drilling, types of formations that are being drilled, the kinds of completions that are getting done before you get a more granular view of what is really going on out there.

I think that's a view we have and I think is a strategic advantage that we have. But I think it's important to sort of stay away from averages, because I think you can actually draw the wrong conclusions about the health of the industry.

That's great color. My follow-up is on the international front. What region do you think will lead way out and what product lines you think -- if frac is where you are very well-positioned in the US, among others, to kind of lead, where do you think internationally Halliburton is best positioned to lead on the way out internationally?

Look, I think the Middle East has demonstrated the most resilience. And I think that when we think about our business we tend to think more mature fields, unconventionals, and deepwater. So from a mature field standpoint, setting aside the Middle East, I think Asia probably has the next chunk of runway and we are very well-positioned there, I'd say, in all of our service lines.

Okay, thanks. Appreciate all that color.

Jim Wicklund, Credit Suisse.

I think that's great of you guys to save the best for last, I appreciate it. Mark, welcome back to the conference call.

Glad to be back.

We look at the results and you give guidance in Q3 that margins will improve. The whole industry has had trouble keeping up with the decline in activity and now that we are starting to stabilize that gives you guys an opportunity to catch up.

At what quarter -- Q4, Q1 next year -- at what point should we expect you to get to breakeven in North America?

I think right now, just as we triangulate, it would be Q1 of next year. I think that's where we will be.

That's very helpful.

(multiple speakers) coming out of that (multiple speakers).

The way incrementals work we never can -- we are stuck with guessing.

The second thing, playing golf the other day with a couple of guys in the forgings business, which is kind of leading-edge, I got a report that the largest frac pump forging order in 12 months has been issued. And I'm not assuming it's you guys, because you guys do a lot of -- most all your own work.

But are we to the point in terms of sentiment -- and you mentioned optimism by your customers and clearly you are optimistic. Have we gotten to the point that service companies are now willing to look at increasing CapEx in anticipation of 2017? And that really applies more to your state of mind for the future.

You guys state that the recovery this year will be anemic, but it will get better next year. Are we starting to free up that sentiment in terms of capital from the service side?

Look, Jim, it's interesting. Forgings actually indicate more to me that they are trying to replace cannibalized parts in a lot of ways. Forgings tend to be consumables as they repair equipment, so one could interpret that as we have run out of cannibalized equipment and now we are having to replace things. So I don't see that as maybe the change in sentiment that maybe you do.

But -- so anyway, that's the view.

I will take restocking consumables. I'll take that as the first step.

Okay, step one.

Okay, guys. I appreciate it, thanks much.

Thank you. I would now like to turn the call back over to management for closing remarks.

Okay. Thank you, Shannon. I would like to wrap up this call with just a few key takeaways.

First, we like our position. We have maintained our global integrated service footprint, outperformed during the downturn, and taken share.

Second, for North America, the landing point is now behind us and our customers are talking about growth, not survival. And, finally, we are the best-positioned for the recovery. We will own the last mile; continue to address our cost structure and collaborate with our customers to maximize their asset value.

Look forward to talking to again next quarter. Shannon, you can close out the call.

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.