Halliburton Company (HAL) — Q2 2016 Earnings Call Transcript

Good morning, and welcome to the 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'll 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. Our North America revenue was down 15% from the prior quarter, significantly outperforming a 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 this second quarter will mark the trough for our earnings. Now we're 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 2 distinct factors at work in North America; psychological and economic, and I think it's 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's 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 was a growing survivor mentality out there, and you can't underestimate the positive change in attitude that we're 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. 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. So 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 incoming train.' 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, access the high yield markets, look at reserve base lending, or partner 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 2 years has been a period of significant under-investment, 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 5 years. Now, you can choose your own energy supply expert and there are many of them out there, but most agree we will need between 18 and 22 million barrels per day of new production by 2021. Meaning we have to find nearly 2 Saudi Arabias worth of production in the next 5 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're not there yet today. The 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 experience lost to retirement and cutbacks. We’ll have to find sustainable ways to deepen the relationships between operators and service companies, collaborating to integrate better, eliminate duplication, and drive down delivery cost. And 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, becoming more meaningful as we go into 2017. And now that we have seen the flow 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, and 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 reached 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 have 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 increase 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 in 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 the Middle East and 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, and 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 expenses for the second quarter totaled $60 million and we expect third quarter expenses 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%. These unusual rate results from having tax losses in the US that are then offset by taxable income in 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 costs 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 on permanently reinvesting our foreign earnings and some adjustments related to the carry-back 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 back-end 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 alternately 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 mid-teens 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. And finally, third quarter Eastern Hemisphere revenue is expected to be down modestly in 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'll 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. Now what I mean by that? I believe it will only take 900 rigs to consume all of the horsepower available in the market. Why? We know the North American market best and we're in every single part of that market. What's 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've seen the attrition of equipment, people, and companies. Let me take these in order. First, horsepower attrition continues due to scrapping and cannibalization. We believe up to four 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 reduced directional cost. We're doing it. Third, increased utilization; we’re 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're making significant progress towards reducing our annual cost structure by $1 billion. We've reduced headcount and consolidated facilities in every region. At the end of the second quarter, we're about halfway there, both internationally and in North America. We anticipate the remaining savings will come in the second half of the year and will reach the $1 billion run rate cost savings as we go into 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 white space in the calendar. This is why we work with customers that 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 bar room row. In certain situations, as we've seen signs of recovery, we've elected to walk away from money losing jobs in recent months. We've been reviewing every contracting and program down to individual wells on a pad-by-pad basis, including opportunities for pass-through and cost-related pricing and surcharging. It's a tough market, but we believe pricing will recover as activity increases. When we have these 4 things, we're confident our North America margins will return to double digits, but beyond North America land, our key focus areas are unconventional, mature fields, and deep water, and I'm pleased with how we're executing around the world. Though they may be limited, we're 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've made significant inroads in our IPM 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 deep water 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 growing times, BaraECD has helped break records on the 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 the drilling solution, including drill bits and fluids for exploration well, reducing the drilling time by 14 days. This cost savings helped 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 our new resource for customers and partners called iEnergy, available through Landmark. It's an open architecture approach to problem-solving. 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 client's asset value, which means a 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 a dead focus on service quality. To sum it up, we like our position. As we expected, the North American unconventional market has responded the fastest, demonstrated by the recent activity pick-up. International markets will take more time to rebound, but we're 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 incidence rates so far this year and it's important we keep this focus on safety and service quality as the market begins to pick up. Now I’ll 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 upcycle. 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 a billion dollars lower run rate going into 2017. We remain laser focused on consistent execution, generating superior financial performance, and providing industry-leading shareholder returns. And 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.

Good morning. Jeff, as someone who spends an inordinate amount of time on headlines and titles, I really like your rig count headlines. It’s a good one.

Thank you.

You stated that about four 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 is in more of a mothballed state? And overall where do you think these figures could stand by year end?

Let me go, maybe start with how we get to the 900 as the new 2,000 and then address your question along the way. So going into the downturn, equilibrium was about 2,000 rigs and 600 frac crews in the US. So a little more than 3 rigs kept every frac crew busy. Really 3 factors at play here. First, drilling efficiency and then completions, intensity and attrition. So from a drilling efficiency standpoint, rigs have gotten almost 30% faster meaning more wells per rig 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 makes up 500. And so then we get to the attrition part of that, and there are estimates that range from 3 to 7 million horsepower that have left the market. We think it's about 4. We see that because we're out in the market every day looking at horsepower. But the fact is there's more horsepower that trips 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. A quick follow up. We hear that some of the most dilapidated fleets that require 20 million, 25 million per fleet to reactivate are giving that really a full refurb of all the key components that’s 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?

Certainly, we maintain our equipment with the future in mind, ensuring that it doesn't require additional capital. However, I believe that equipment that has not been properly maintained and has been cannibalized may be challenging to economically reintegrate into the market.

Great. Thanks.

Good morning gentlemen and congratulations on a well-executed quarter. So Jeff, probably for you in terms of the North American land market, and really just because of the devastation of the industry, particularly your competition, we see a lot of bottlenecks that are going to appear, labor, working capital, attrition like you discussed, the logistics. Could you maybe comment on what you see from the 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 lot?

Thank you, James. Yeah, you nailed it. The pinch points will be equipment, sand, and people. We spent time on equipment, but clearly the approach we've taken around equipment is to be best positioned to get that equipment back into the marketplace. So we’ve talked about that. From a sand standpoint, it's not the sand as much as it is the logistics and in our view we're 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've been careful as we've gone through these restructurings to do our very best anyway to retain experienced people and we have those today. Then don't forget it was just in 2014, we put 21,000 people on to the payroll and so we know how to do that and we know how to make those people effective. So we feel like Halliburton is well positioned.

Right. I totally 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, you understand these bottlenecks, these issues?

Yes, I do. It’s part of the flight to quality. As I described 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.

Thanks. Good morning. Dave, I was hoping to get a little more color about your thoughts on thinking about North America over the back half of the year. Oil touched 50 as you noted. It’s 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? It sounds like the 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 start that, and then maybe follow up. We call it a landing point, which means rigs stop falling, but I think it's important that it's a sentiment that trumps the oil price right now. 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 in the plan so moving up from what were clearly the worst plans. And I would call it a measured step up as opposed to a boom. And so certainly seeing positive things, we think we will be well positioned for whatever shape that recovery takes.

Okay. No, that's helpful. Thanks. My follow-up is maybe from Mark. Mark, the margin guidance for North America up. I think you said 100, 200 basis points. That implies probably lower incremental margins than I would have thought given the cost-cutting you guys are doing. Can you maybe talk a little 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 the sentiment has changed, we’re 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 depress that quite a bit. There are, because you can see it in our numbers, there’s equipment out there that's ultimately not covering fixed costs. And so we're 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's going to continue to add margin points here on everything. I guess what we're saying is, we're not counting on price at this point. The market itself, this utilization and what we're going after, we'll fight for price every single day, but it’s still this hand-to-hand combat is just set out there and so we're not necessarily baking that into the forward look today.

Okay, all right. Thanks guys. I'll turn it back.

Thanks. Good morning guys. So 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 mind that frac utilization will probably be near the last cycle peaks of 90%, and then if you can take that another step forward, 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 believe we should first consider pricing. It will be influenced by utilization. As we have previously mentioned, we expect utilization to start tightening, which will lead to opportunities for margin improvement that aren't necessarily related to price. We did not experience significant pricing leverage in the last cycle. We were approaching that in late 2014, just as things began to slow down. Much of our value creation is derived from an efficient platform that optimizes utilization. Moving forward, I expect to achieve similar results to what we accomplished last time, likely with better outcomes since we have already addressed some structural costs. Therefore, I am very optimistic about future prospects.

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

Yes, certainly.

Very helpful. And 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? And also it was very impressive you saw some market share gains in your international markets. Maybe you could talk about that a little bit.

Yeah. So typically international business will trail US behavior by 6 to 9 months and it’s 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 a, in my view margin resilience is really reflecting better visibility that we have because of the longer timeframe and our team, the Alberta team just absolutely executing on all points.

And then on the market share again?

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're 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’s certainly some pricing pressure there. There's certainly some issues with customers trying to lower their cost per BOE. I think it's the deep-water complex that is the most challenged in this commodity price environment, and 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 deep-water complex. But where pricing is today, it just doesn't work generally in deep water, especially the new deep water. So we’ve 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 now 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.

Thanks. Good morning. Mark, back to the North American margin question. Just trying to understand it better. If you just focus on the quarterly rate of change and let’s just presume, you made a prophecy I think with reason that your revenues would markedly outperform the rig count in the third quarter. Just presuming a 10% increase in topline and only a 200 basis point improvement in margins, that implies a 15% incremental. At this stage, that just seems to be woefully anemic, recognizing the fact that you're unemployed 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'm glad you asked that question because I wanted to mention a point I didn't get to make earlier. We're starting to notice some cost inflation in the marketplace, particularly with diesel and other commodities. Believe it or not, we are beginning to address inflation at this stage. It's challenging because we are currently at a low growth rate, and we need to increase capacity utilization before we can effectively raise prices. We will push for this, but some commodity prices are beginning to rise, which is impacting us and is reflected in our current situation.

Okay Jeff, regarding the changes in your Q2 stage count, how would you describe its evolution? Specifically, was the stage count at the end of June significantly higher than the average for Q2?

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

And 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.

Hey, good morning. So just sticking on 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. Thinking about your thoughts on what will it take for pricing to move higher and how much you 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. So we continue to look at every crew in terms of what's economic. And as we 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. So we continue to view it that way.

Okay, fair enough. And then Mark, you talked about, in previous discussions you talked about being opportunistic on some of the upcoming debt maturities. Maybe you pay down so much cash on hand, maybe in some cases you extend, so depending on what the market is giving you. Capital markets is 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 to 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 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, you'll notice that we've 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, our current plan is to just continue to naturally delever.

Understood. Thanks for your time.

Hey, 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 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 operations.

Look, 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 would be structurally a positive in the UK sector or the North Sea but immediately, no impact.

Okay, great. And then similarly, you talked about the 6 to 9 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 that the positive signs are going to be production. It’s pleasing to see in Brazil for example, Petrobras is 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 is the kind of market that over time will 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, or what do you think is going to be that trigger, like you said?

I think it's later partly because you've got 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 too and it’s very unfortunate, but I hope to see resolution over time.

Part of it is just the natural budgeting cycle for many of our NOC clients. Their annual budgets need approval from legislative bodies. They are operating in a year without significant spending and limited cash flow, which means that until those budgets receive approval, they won't be spending. This often results in delays until late in the first quarter or even into the second quarter before everything is approved. Consequently, this pushes out the ramp in spending. Even if they encounter higher prices, the ramp in spending is delayed more than it typically would be. In contrast, in North America, they are not dependent on legislative bodies and can start spending quickly as soon as they have the cash flow.

Thanks. Dave, you talked about the psychology of the E&P getting better. I was just curious, one big part of that has to be the lower breakeven cost that they're seeing. I’ve been seeing a number of presentations from E&Ps who seem to think that the costs 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're kind of locking in the next couple of years? I'm just kind of wondering what that part of the psychology of the cost side.

Good question, Dave. I think the conversations go like this. Hey, we've finally driven service prices down to where we can breakeven, sort of a plus 40. My response to that is yeah, for right now, but you're not going to have any service industry to 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. And you know Jeff hit on some of them. Rig efficiency is sustainable. That 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'll be give and take and my guess is as we listen to the calls over the next few quarters, the operators will say they've got them locked in and the service companies are going to say we've got to have price increases and we'll end up in the middle somewhere like we always do.

There seems to be a disconnect that will play out over the next year or two, but there is recognition that service costs will have to rise eventually. Do you think, deep down, they realize that some adjustments are necessary?

Correct.

Hey, good Morning. I just wanted to calibrate, see if you guys could calibrate some information for me. So you guys talk about a 4 million horsepower reduction in the US frac market. So that puts maybe the market at about 14 million horsepower give or take. We’ve heard depending on who you want to talk to, maybe about 6 million of that horsepower is currently active in the market. 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 jibe 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 man, I don’t think those numbers are inconsistent with how we view the market and that's why we described the path back is it starts with utilization of what's there. I think there are barriers to a lot of that equipment ever making it back into the market and I do think that unintended equipment almost retreats on its own, particularly with cannibalization that we hear others talking about it. So I don't think you're wrong.

So then in the context as we try to think about the opportunity for margin improvement vis-à-vis pricing, do we need to get back up to 8 million horsepower now 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 just to drive some pricing? Any viewpoints on that?

Let me address that. We're not going to discuss pricing strategies today. We have a plan that we will follow privately, and this will be a conversation tailored to each customer. It's crucial to recognize that not all pumping equipment is equal. There are some companies with no utilization because they lack customers, operate in unsuitable areas, or have equipment that isn’t compatible with the formations they are targeting. There's a clear distinction among pressure pumping companies, and many people tend to generalize and refer to averages. I think it's essential to differentiate the market based on various basins, customer drilling activities, formation types, and completion methods to gain a clearer understanding of what's happening. This perspective gives us a strategic edge, but relying on averages can lead to incorrect assumptions about the industry's health.

All right, that's great color. And my follow up is on the international front. What region do you think will lead the way out, and what product lines you think if frac is where you're very well positioned in the US among others to 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 deep water. And so from a mature field standpoint, setting aside the Middle East, I think Asia probably has sort of the next chunk of runway and we're very well positioned there, I'd say in all of our service lines.

I think that's great that you guys saved 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're 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, Q1 of next year. I think that's where it will be.

Okay. That’s great, but the way incrementals work, we never can be sure. The other day, while playing golf with a couple of colleagues in the forgings business, which is quite innovative, I learned that the largest frac pump forging order in the last 12 months has been placed. I'm not assuming it’s your company, as you handle most of your work in-house. But are we at a stage where service companies are beginning to consider increasing capital expenditures in anticipation of 2017? This really reflects your outlook for the future. You mentioned that the recovery this year will be slow, but it will improve next year. Are we starting to see a shift in sentiment regarding capital from the service sector?

Jim, it’s interesting. Forging actually indicates more to me that they are trying to replace cannibalized parts in a lot of ways. Forging tends to be consumables as they repair equipment. One could interpret that as we've run out of cannibalized equipment and now are having to replace things. I don't see that as maybe the change in sentiment that maybe you do. But anyway …

I’ll take restocking consumables. I’ll take that as the first step.

Okay. Step one.

Okay, thank you, Shannon. I’d like to wrap up this call with just a few key takeaways. First, we like our position. We've 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’re the best position for the recovery. We will on the last mile continue to address our cost structure and collaborate with our customers to maximize their asset value. Look forward to talking to you again next quarter. Shannon, you can close out the call.