Baker Hughes Company (BKR) Q2 2012 Earnings Report, Transcript and Summary

Hello. My name is Dawn, and I'll be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Second Quarter 2012 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Trey Clark, Vice President of Investor Relations. Sir, you may proceed.

Thank you, Dawn. Good morning, everyone, and welcome to the Baker Hughes Second Quarter 2012 Earnings Conference Call. Here with me today are Martin Craighead, President and CEO, and Peter Ragauss, Senior Vice President and Chief Financial Officer. Today's presentation and the news release that was issued earlier today can be found on our website at www.bakerhughes.com. Additionally, reconciliation of operating profit and non-GAAP measures to GAAP results for historic periods can be found on our website in the Investor Relations section under Financial Information. Finally, I must caution you that any company outlooks discussed this morning or as of today are subject to various risk factors. We'll try to highlight these risk factors as we make these forward-looking statements. However, the format of the call prevents a more thorough discussion of these risk factors. For full discussion of these risk factors, please refer to Baker Hughes's SEC filings and, in particular, the forward-looking disclosure in this morning's news release. With that, I'll turn the call over to Martin. Martin?

Thanks, Trey, and welcome to your first quarterly call. Good morning, everyone. Baker Hughes delivered improved results in the second quarter. While there were a lot of headlines around prices for oil, natural gas and NGLs, rig count actually only moved about 1%. Perhaps the story that grabbed the most headlines was the price of guar. However, by executing with focus and discipline and leveraging our balanced portfolio of products and services, Baker Hughes delivered 2% sequential growth in operating income. The real story behind this success is the sense of urgency we applied to North America. Initiatives we implemented to improve our Pressure Pumping business are on schedule. Furthermore, our Drilling and Evaluation, Completion and Artificial Lift businesses posted outstanding results. Our International business delivered improved revenue and operating profit as well, driven primarily by outstanding performance in Europe and the Middle East. In a moment, I will share with you what we're doing to continue improving the quality of our earnings. But first, I'll turn the call over to Peter for more detail on the quarter. Peter?

Thanks, Martin. Good morning. This morning, we reported net income for the second quarter of $439 million, which is $1 per share. Revenue for the second quarter was $5.33 billion, up 12% or $585 million from last year and down 0.5% or $29 million sequentially. Adjusted EBITDA for the second quarter was $1.02 billion, flat to last year and up 3% sequentially. To help in your understanding of this quarter's results, I'll bridge last quarter's EPS to this quarter. In Q1, we posted earnings of $0.86 per share. Subtract $0.07 for North America operations, primarily due to the seasonal reduction in Canadian activity. Add $0.04 for International operations as every International segment posted increased operating profit. Add $0.04 for Industrial Services as a result of the seasonal rebound in activities, particularly in our process and pipeline services business. Add $0.02 for lower corporate costs. Lastly, add $0.11 for the lower taxes as this quarter was favorably impacted by the reversal of certain tax reserves. That brings us back to the $1 dollar per share. Looking at the year-on-year bridge, starting with $0.77 in Q2 of last year, add back $0.16 for expenses related to Libya. This brings us to the adjusted $0.93 we discussed in the second quarter of last year. Subtract $0.13 for North America operations as a result of less favorable market conditions for our Pressure Pumping product line. Add $0.08 for International operations resulting from steady International growth, particularly in Europe and the Middle East. Subtract $0.03 for higher corporate costs, partially due to approximately $10 million quarterly of noncash amortization that we highlighted back in Q4 2011. Finally, add $0.15 for a lower overall tax rate primarily related to the reversal of certain tax reserves previously highlighted. That brings us back to the $1-per-share figure. And Table 4 of our earnings release will provide financial information excluding the impact of certain expenses in Libya in Q2 2011 as a result of civil unrest. From this point on in the conference call, any comments on revenue, operating profit and operating profit margin refer explicitly to Table 4. Moving to North America. Revenue was $2.7 billion, up $300 million or 13% compared to a year ago and down $191 million or 7% sequentially. Sequential decline in revenue resulted from the seasonal reduction in Canadian activity following the spring breakup. In the United States, our revenue was higher compared to the first quarter. North America operating margin was 13.4%, down 60 basis points compared to the previous quarter. Similar to revenue, the sequential decline in North American margin can be attributed to Canada, which was mostly offset by improved margins in the U.S. Let me summarize our performance in North America into 3 points. First, our self-help initiatives and actions to reduce costs offset the market volatility impact to our Pressure Pumping business. And this helped stabilize margins. The most well-publicized story of this volatility was guar beans. While our costs continued to increase for the most part, we were not able to pass them on to customers. Pressure Pumping pricing remained very competitive, especially in the gas basins and in the Eagle Ford. Pricing for other basins, such as the Permian, remained stable. Second, every other product line in U.S. line had very strong results during the quarter. We're very pleased with the performance of our drilling systems, completion systems and production product lines. The rapid shift from natural gas to oil is driving strong demand and improved pricing for our Artificial Lift and Chemical product lines. The third and final point is that our results from the seasonality of spring breakup in Canada were just as expected. Moving to International. Revenue was $2.3 billion, up $259 million or 12% compared to a year ago and up $122 million or 6% versus the prior quarter. International operating profit was $320 million, up $48 million year-on-year and up $25 million sequentially. International operating margin was 13.7%, up 60 basis points year-on-year and up 40 basis points sequentially. Both sequentially and year-on-year, each International segment delivered increased revenue and operating profit. In fact, we recorded the highest revenue in operating profit in Europe and the Middle East since the Baker Hughes geomarket reorganization in 2009. Our Europe, Africa, Russia Caspian segment delivered strong results for second conservative quarter. Operating margins exceeded our expectations, primarily due to Europe, where our Drilling Services, Wireline Services, Completion Systems and Artificial Lift product lines performed well across the region. In Africa, as expected, the favorable product mix during the first quarter did not repeat. In the Middle East, Asia Pacific region, we saw sequential margin improvement as well. Overall margin increased 75 basis points as strong Completions and Artificial Lift sales in Saudi Arabia were complemented by increased drilling activities throughout the region. In Iraq, revenue continued to grow rapidly as our business expands. Latin America also delivered improved results sequentially, with revenue increasing 5%, operating margin increasing 105 basis points. These results are largely attributed to higher activity cost per region, particularly in Mexico, Argentina and Venezuela. For our Industrial Services segment, revenue was $321 million, up 14% sequentially due to typical seasonality. Increased Pipeline Inspection and commissioning as well as polymers activity drove strong incrementals. As a result, operating profit was up $22 million or 100% sequentially, with operating margin of 13.7% for the quarter. Turning to the balance sheet. Overall, our balance sheet at the end of the quarter remained strong. Our total debt was $5 billion, up $514 million from the prior period. This increase was primarily to fund the U.S. working capital and capital expenditures. Our total debt-to-capital ratio was 23%. Capital expenditures for the quarter were $771 million. And at the end of the quarter, we had $792 million in cash. Now let me provide you with our guidance for the remainder of 2012, starting with rig count. For North America, we now expect the average annual rig count to grow about 3% year-over-year from an average of 2,296 rigs in 2011 to an average of 2,371 rigs in 2012. We expect to exit 2012 with 488 natural gas rigs in the U.S., which is a decline of 321 rigs compared to last year. For oil, we expect to exit 2012 with 1,430 rigs in the U.S., which is an increase of 300 rigs compared to last year. I will now give our third quarter outlook for North America. We expect continued activity and margin improvement in the Gulf of Mexico as the deepwater rig count continues to increase. In Canada, activity will rebound, but the current pace is disappointing. Revenue and margins are expected to be challenged as Pressure Pumping market conditions and cost issues experienced in the U.S. begin to impact that market. Similarly, we expect Pressure Pumping in the U.S. to continue facing weak market conditions. And we expect margins will be eroded during the quarter by higher guar bean costs as we consume inventory purchased at peak prices during the second quarter. While the outlook in North America is very difficult to predict in the current environment, we would like to share our view of margins for the third quarter. The seasonal increase in Canadian activity will be partially, if not entirely, offset by continued weak market conditions in Pressure Pumping and higher cost for guar beans. In summary, we expect North America margins to be flat to slightly up compared to the second quarter. For the International rig count, our forecast for 8% year-over-year growth has not changed. This excludes the impact of Iraq, which Baker Hughes began including in our rig count in June 2012. The most significant growth will remain in the Middle East, Latin America and Africa. Our International margins are expected to continue to increase this year with the Q4 exit rate higher than Q4 2011. Industrial services should see growth in Q3 but will likely decline in Q4 due to typical seasonality. We expect interest expense to be between $55 million and $60 million for Q3. Corporate costs are expected to be between $80 million and $85 million for Q3. Depreciation and amortization expense in Q3 is expected to be between $395 million and $405 million. Our expected tax rate for the full year continues to be between 33% and 34%, which means we expect a tax rate of about 36% in the second half. Lastly, capital expenditures for the year are still expected to be between $2.7 billion to $2.9 billion. At this point, I'll now turn the call back over to Martin.

Thanks, Peter. In North America, our management team has made good progress executing our Pressure Pumping improvement plan, while every other product line has delivered very strong results. We start by providing a brief update on the productivity, supply chain and technology elements of our Pressure Pumping plan. Starting with productivity. We continue to enhance the utilization of our workforce and at the same time, to improve the utilization of our fleet. We added additional 24-hour fleets in the second quarter. And in fact, right now, we have more 24-hour fleets than at any point in our history. One example of our efficiency improvement is stages per fleet per day, which increased 10% over the previous quarter. We also made progress in adding considerable infrastructure in the right basins in order to improve operational efficiency. And we finished relocating our fleets to the oily basins during the quarter. Shifting to supply chain. We continued to make good progress on freight and logistics as we work to optimize shipping lanes and rationalize carriers in the interest of leveraging volumes and better coordinating shipping schedules. We've also beefed up our procurement function and made careful and calculated decisions on commodity-based consumables, such as proppants and guar. As you know, the cost of guar has become a recent source of volatility for the service sector. While prices reached a peak of $12 per pound in the second quarter, in the past few weeks, they've come down to around $5 per pound. When you consider the market drivers for guar, there is a reason to believe the downward pricing trend will continue. And while that could be good news in the near term, guar is still a farmed product. And we cannot continue to subject our customers nor our income statement to this uncertainty. That brings us to the final part of our Pressure Pumping improvement plan, and that's the role of technology. Baker Hughes has a long history of delivering solutions through technology. As we highlighted last quarter, we continue to increase our technology spend in Pressure Pumping. To that end, we focused the experts in our fluids and chemicals labs to develop alternatives to guar. During the quarter, we accelerated the introduction of AquaPerm, a linear gel fracturing system that is proprietary to Baker Hughes. So far, our AquaPerm system has replaced approximately 5% of our guar volume in the second quarter, and there is the potential to double that in the second half of this year. In addition, we're also working on the next generation of cross-linked fluids to replace guar. Our operations, technology and supply chain teams remain laser-focused on the initiatives to improve our Pressure Pumping product line. As Peter highlighted, every other product line in U.S. land operations performed very well. And that serves as a firm reminder of the impact of our technological contributions. In Drilling Services, our position with rotary steerable systems continues to expand. Our AutoTrak Curve system was formally introduced a little over a year ago, and since then, it has been extremely well received in the market. AutoTrak Curve can do in one efficient pass what it takes other directional drilling systems 3 passes to accomplish. This drilling technology provides more wellbore exposure within the reservoir. We've already drilled over 1 million feet in just a year in the U.S. To put that into perspective, the previous generation of the AutoTrak system took 3 years to hit the 1 million-foot milestone. Our completion systems product line remains a core strength and continues to outpace the market. Products such as our FracPoint sliding-sleeve technology are gaining further traction as more and more customers improve efficiency by moving to all-sleeves completions rather than a hybrid completion with both sleeves and plugs. Furthermore, we're seeing more uptake of sliding-sleeve completions in oily plays such as the Permian and Niobrara. Elsewhere in North America, our Artificial Lift product line continues to deliver strong results. We're seeing new markets for electrical submersible pumps, or ESPs, in unconventionals. In the Mississippian play, we estimate that 60% of all oil wells needing Artificial Lift technology are having ESP systems installed. In fact, some operators are bringing new power lines into their fields to enable ESPs. Baker Hughes's ESPs allow customers to manage the initial startup and production profile of the well in order to minimize the damage to the fractures, thus maximizing their ultimate recovery. Moving to international markets. We continue to make steady progress in the Eastern hemisphere as we ramp up activity in support of new contracts. Our balanced approach to investing in infrastructure while managing costs contributed to the sequential and year-over-year margin improvement we highlighted previously. In the Middle East, we're experiencing solid growth, especially integrated operations. And we believe the IO market represents a significant opportunity for Baker Hughes. For example, our integrated operations in Iraq represent the largest and fastest startup in the history of our company. From 0 drilling rigs in March, we exited the second quarter operating 6 drilling rigs and expect that to grow to 9 drilling rigs by the end of this year. We've taken a disciplined approach, as we've highlighted in the past, to entering this challenging market, and we're pleased with our progress. Following this success, we've recently been awarded a long-term engineering, project management and integrated operations drilling contract by Saudi Aramco for turnkey delivery of over 75 wells in the Shaybah field. This project, along with additional awards in Iraq and in the Kuwait-Saudi neutral zone, are providing a solid foundation for growth in this region. I'm also pleased to report outstanding performance from our Europe, Africa, Russia, Caspian segment. And in Latin America, increased activity in Venezuela and the Andean region continues to benefit our production product lines. As we look to the rest of this year and into 2013, it's a story of 2 differing markets. Activity in international markets continues to expand, and pricing remains stable. We're focused on growing our integrated operations business while taking a responsible position on margin expectations for new contracts. We continue to optimize our supply chain strategic sourcing in order to position our manufacturing and supplier content in lower-cost locations. This, and continued focus on reliable and efficient performance, will pave the way for Baker Hughes to improve international margins. The North American market holds more uncertainty. Assuming natural gas futures fall back to $3 and WTI holds above $85 a barrel, overall U.S. activity at year end should look similar to what we're seeing today. As for our North America customers, we believe there is a heightened bias to maintain capital discipline. Nevertheless, in our current price environment, there has not been a wholesale change in activity levels across the wider customer base, and we don't anticipate one. Regardless, North American Pressure Pumping market continues to face overcapacity issues. In fact, we see signs that the pricing pressure experienced in the United States is creeping across the border into Canada. Until this environment improves and the supply and the demand curves balance, Baker Hughes will not be adding another horse to the herd. Today, the few remaining fleets to be delivered this year will not be going into service right away. Our focus will remain on executing our plans to continue improving Pressure Pumping margins and maximizing utilization of our existing fleet. We are bullish on our ability to harvest the value our other product lines can offer the market, and we will continue to invest in those businesses. In addition, we are particularly pleased with the outlook for Gulf of Mexico as our business has returned to pre-moratorium revenue and margin levels. We're also realizing price improvement as activity ramps up. Furthermore, we predict that the Gulf of Mexico activity will continue growing, and the active rig count at the end of this year is projected to include 29 active deepwater drilling rigs, up from 24 active today. Our strength in high-technology Completion and Production systems will provide additional growth as our customer shifts from exploration and appraisal to multi-well development campaigns in 2013. In closing, we remain focused on the quality of our earnings and the disciplined deployment of our capital. So with that, Trey, let's go ahead and open it up for some questions.

Thank you, Martin. At this point, I'll ask the operator to open the lines for your questions. [Operator Instructions] Dawn, can we have the first question, please?

[Operator Instructions] Our first question comes from the line of Kurt Hallead with RBC.

I was curious -- well, first and foremost, I mean, the improvement sequentially in North America driven by everything outside of the frac business really underscores some pretty significant strength. You guys provided your outlook [indiscernible] and it seems like things are kind of flat to maybe slightly higher as you head out into the third quarter. Have we seen the worst of the frac pricing situation right now? What was the greatest intensity in the second quarter? Can you give some color on that so that we can kind of frame the second half of the year and how these other product lines are going to potentially offset what's happening in the frac business?

Yes, Kurt. You asked about a couple of things there. So you asked about pricing on the Pressure Pumping. So let me address it this way. We have some basins that are, let's say, the worst pricing, which would be your NGL-driven activity right now. But interestingly, I think as this quarter came to a close, it was becoming apparent that a lot of the capacity had moved out of the gas basins. As you heard us say on the call, we're pretty much there, if not all there, in terms of what we want to move. That's going to equalize the supply-demand situation. So we don't expect any more meaningful price deterioration in the basins that have given us problems in the past. Obviously, I think the old basins are pretty well balanced. You do have one basin that, like I say, is going through some rapid change, given the NGL situation. But other than that, I'm a little bit more optimistic now. I'm not saying pricing isn't going to continue to creep down overall, but it's definitely decelerated. And that's a positive. If you asked also about the pricing in our other product lines and the impact on that, it's really a technology type of driven event, Kurt. And you can go through all the different product lines. I don't want to do that right now. The guys can probably give you some color. But as I highlighted briefly, rotary steerables, particularly the Curve, some of the new technology on the Artificial Lift and, of course, FracPoint and all the derivatives of that are still driving some pretty impressive price gains, depending on the basin, depending on the customer and the application. So I don't know if that answers your question.

No, I mean, it's helpful. It's just your commentary is being somewhat cautious on the progression on Canada, obviously, with some additional pressures on frac. I was really trying to kind of gauge your level of conviction in this 300 to 400 basis point of self-help improvement you guys had indicated over the last couple of quarters in North America. And I'm just trying to, for one thing, get your conviction on whether or not you'll be fully -- be able to fully recognize that 300 to 400 basis points as we get into the second half of the year.

Go ahead, Peter.

Well, this is Peter. We don't have that much conviction since we've delivered most of that already. I think we came a little bit earlier. We had quite a few good, quick wins. Our utilization of our workforce is a lot higher than it was, say, even 2 quarters ago. We're running more 24-hour frac fleets. Our logistics and freight costs have come down sequentially, so we feel pretty -- in fact, we're there, pretty much, on meeting that self-help. It doesn't mean there isn't more that we've identified that can't benefit us in later quarters. Quite -- and a lot of that has to do with customer mix and utilization, which, I think, take a little bit longer to realize. But as far as the reduction in costs and getting more efficient, we have achieved quite a bit of it already.

Okay. And maybe if I can have one follow-up here on use of cash on a go-forward basis, how would you prioritize that?

Initially, to pay down our commercial paper, which is about a little over $1 billion right now, so that's the obvious one. We've had quite a bit of increase in working capital in the first half of the year as we've taken on proppants, guar, et cetera. So we want to pay some of that working capital down. But we're still cash negative for the year, and I think what we want to do is continue to get ourselves in a cash positive position before we start worrying about increasing returns and that sort of thing.

Your next question comes from the line of James West with Barclays Capital.

A quick question on the international side, Martin, particularly on Latin America. We've seen, obviously, some pretty big contracts go through in Brazil or at least are in the process of being finalized. There's been a lot of market share shifts, it looks like, in that market. And I recognize those won't go into effect until probably the end of this year or early 2013, but how is Baker Hughes set up for this change? Because if I am reading -- if my Portuguese is correct and I'm reading these contracts right, it looks like you have given up some market share. And I recognize that you guys are thinking about it as your market share, probably, as margin versus some that might think about it as revenue. But is there the potential that we might see Latin America going into the next year slip in terms of top-line-type growth? Or am I overstating kind of the changes in Brazil?

Well, James, there's a whole lot of rhetoric around that, so I want to limit my comments. But I'll put it this way. The contract you referred to, I know pretty well. I was fortunate enough to be involved in our drilling segment when that contract was awarded to us 5, 6, 7 years ago. I really can't remember now. And it's a meaningful piece of business for us. There's going to be a likely shift in share, but our presence there will still be significant. And I think that some of the rhetoric -- what's lost in all the rhetoric, I should say, is the fact that there's no guarantee of share. You have to earn the share. What the contract provides you is a opportunity. And performance is everything for Petrobras. It's everything, obviously, in those basins. So we're -- I've got to tell you, I haven't lost any sleep, and it's a bit of a nonevent in terms of the way the decisions were made. We felt comfortable with our pitch, given our time there, our cost structure, our infrastructure, our knowledge of the reservoir. So I think what you may want to take away, as you've seen in parts of Mexico, you saw it in Saudi Arabia 5 or 6 years ago, the only winner here, actually, might be the customer.

Right. Okay. And so -- and we could -- if I articulate kind of how you -- how that contract had worked out the last 5 or 6 years, your performance has been excellent, if I remember correctly?

Both operationally and financially. And by the way, we just received an extension well into next year. No changes in pricing and activity for us. So like I say, down there, you get what you deserve. And so we're not worried.

Your next question comes from the line of Bill Herbert with Simmons & Company. William A. Herbert - Simmons & Company International, Research Division: Peter and Martin, I'm not sure if you provided us, and if you did, I didn't hear it, but any thoughts with regard to international margin possibilities for the third and fourth quarter, respectively? You did 13.7% in the second quarter, which was a bit better than a year ago and flat to up quarter-on-quarter. Should we expect more market improvement second half of this year with continued seasonal recovery in the third quarter? Or how should we think about it?

Well, your bookends are this quarter at 13.7. And we did say we expect to have an exit rate higher than the exit rate last year, so somewhere above 15.5%. So we've got 200 basis points or so to achieve that, and it's probably a pretty steady grind up from here. And I think the operative word we've been using the last month is grind because it is a volume-driven phenomenon. We are seeing some pockets of price in smaller tenders only to be consumed by discounts on big tenders. But yes, we still feel pretty good about the rig count. We have high visibility on our current contracts, especially in the near term. So we see margins improving from here. William A. Herbert - Simmons & Company International, Research Division: Okay. Good. And then secondly, with regard to North America and specifically Canada, I think you said in the press release that Canada unfolded as expected, which, given the 70% decline in activity, I mean, coming out of Q1, you expected a relatively benign result. Certainly a spring breakup with regard to eroding revenues and margins, but perhaps not as severe as historically you had expected, and given the severity of the rig count compression, and if, in fact, your results were more benign than historical precedent, what drove that delta? Or in fact, was the breakup kind of in line with what unfolded on the activity front, which would -- I mean, your revenues would have been down 15%? I mean, is that what unfolded? Or is it something...

The breakup was in line with last year. There is nothing unusual about it, neither better nor worse in terms of our decline in operating profit coming out of Canada. It's pretty much flattish compared to last year.

What's different, Bill, is the way it's coming back. William A. Herbert - Simmons & Company International, Research Division: It's soft?

Yes, it's very soft. I think, in fact, just looking at some of the numbers over the last few days, our guys, the rig count, where it sits this week, is 3- or 4-year low relative to this time year-on-year. And where gas prices are with the Pressure Pumping saturation up there, I wouldn't expect -- we're not expecting to be able to deliver out of that business unit like we have in the past sequentially, 2 to 3.

And it'll still be up, Bill, but it probably won't be up as much as it was last year at this time. William A. Herbert - Simmons & Company International, Research Division: No, I hear you. So I mean, historically you've done with your Pressure Pumping part of the mix now, you've had a 50% revenue decline, something close to that with regard to decrementals, and then 2/3 revenue recapture in the third quarter, and a 2/3 revenue recapture probably is a reach at this stage, correct?

Yes, that's probably a reach. And don't forget, we've mentioned -- we think our traditional businesses will be affected a bit by the rig count. But you're starting to see Pressure Pumping pricing hitting Canada a little bit, and we are seeing guar cost increases in Canada. So you've got combination of the rig count affecting all the product lines, and you got the unique phenomenon of Pressure Pumping, which is under a little bit more pressure than the rest of our product line. William A. Herbert - Simmons & Company International, Research Division: And I'll slip one more in here. Martin, have you thought about -- we're seeing a pretty significant production response on the natural gas front, and the storage data has much better behaved over the past several months. Have you thought about -- the entire industry, not only you, has sprinted away from natural gas. At some point, we're probably going to revert back to natural gas in some form or fashion. How do you think about that with regard to the logistics and the operational issues attendant to that switch back to gas?

Well, Bill, that's a great question, and we do think about it. But I've got to tell you, it's all hands on deck right now with -- so that would be -- it's going to be a good problem to have to address, and we will have to address it. What I would tell you is that the difference will be, at least for Baker Hughes, when we dislocated out of gas into oil, we went into -- we didn't have the facilities to move into. I want to say we went to a Walmart parking lot, but we had some difficult logistical issues to address. Given what's happened with gas in the previous 3 years, we were well under our way, as was BJ, in building pretty significant facilities. Now those facilities today sit underutilized in the big gas basins. So it would be a much easier, if you will, relocation back in than what we experienced moving into the oil, because we'll have the infrastructure. Now staffing may be a bit of an issue. We'll have to address that. But that should be the only, only item that would cause us any kind of pain, would be the people side. We have the infrastructure.

And your next question comes from the line of Jim Crandell. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Martin, can you talk about where you see the best international prospects over the next 6 to 12 months?

Yes, I can, Jim. By far, it's Middle East, followed by Africa. And then I think you drop down to a Latin America, Europe type of story. And I think Asia Pacific, particularly, is going to continue to, to use Peter's term, grind it out. We just don't see the activity and, therefore, pricing coming back strongly there as we do in Africa and the Middle East into '13. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Could you be a little bit more granular, Martin, and comment maybe a little bit by country, in which countries you see the strongest improvement in activity and, hopefully, Baker Hughes's revenue?

Yes. In the Middle East, of course, it'll be led this year by Saudi and Iraq into '13. And you could probably add on Kuwait as they move more into the horizontal markets. It's going to be fantastic for our business. And Oman should come back a little bit stronger than it was this year. And in terms of Africa, the strength later this year and into next year, I think, differentially will be Sierra Leone, Ivory Coast, of course, the deepwater plays in Mozambique and Tanzania and Nigeria. We could have a very positive surprise in Libya and Algeria. And I wouldn't say we're not banking on it. We are banking on it, but of course, it's got a higher beta right now. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. Could you also comment on what you're seeing right now in international wireline and LWD pricing and then, as a subset of that, what you're seeing in terms of LWD pricing on deepwater jobs?

LWD or wireline on deepwater? James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Well, maybe both.

Okay. LWD D&E, pricing internationally is very, very good, except for the big contracts. And on wireline, it's the same. Call-outs, smaller-term contracts in terms of money or volume or timeframe are getting better. It's the high-profile ones that pricing has been gutted on. Does that answer your question? James D. Crandell - Dahlman Rose & Company, LLC, Research Division: That does. And one quick follow-up is what -- and really switching topics here, what quarter do you see guar becoming a tailwind instead of a headwind for Baker?

Yes. It's going to be the most costly, based on the inventory workout, in Q3. And then if you look at 3 to 4, you'll start to see a -- it will be favorable. And as both Peter and I said in our commentary, it should then pick up a little bit of steam quarter 1 and so forth and hopefully get us back to where it's a nonevent. But like I said, should it be an event, we're taking actions to try to minimize that through either better contracting or replacing it.

Let me just add that Q2 to Q3 will be an increase in cost, just to be clear. Whether or not Q4 comes down to Q2 levels remains to be seen depending on how much we can contract at today's prices. So we're not expecting Q4 to be much below Q2 at this point. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. Peter, how does your -- what do you expect -- what are your last expectations now in terms of CapEx this year?

We said 2.7 to 2.9. You'll see in the press release we've spent about 1.4 in the first half. And we're on pace for the midpoint of the 2.7 and 2.9.

And your next question comes from the line of Bill Sanchez with Howard Weil.

Peter, you mentioned the international rig count growth expectations still at 8% year-over-year, although you noted you had included Iraq in those numbers. And I guess that wasn't the case in the first quarter call since you guys picked it up in June of 2012. When you guys had lowered your rig count forecast internationally last time, you had still maintained a belief that your top line international revenue could grow double-digits. And I guess, Peter or Martin, is that still the expectation now as we look at 2012 versus 2011?

Yes, let me just clarify. The 8% excludes any impact from Iraq. And we feel okay about that. We feel there's a bit of a ramp-up coming in the second half of the year. And of course, we'll obviously update that next quarter. Yes, we still feel okay about double-digit international revenue growth. As I said earlier, we have good visibility of our contracts, prices and so on, particularly in the near term. And we usually are very good at predicting our revenues internationally, and I don't feel that that's changed any -- that hasn't changed in the past 6 months.

Okay. And I would assume, given the international margin kind of exit commentary, Peter, fourth quarter '12 versus fourth quarter '11, we're still comfortable, if not conservative, in the thought process of 20% incremental margins, non-North America, year-over-year?

Yes, I would say we're comfortable, and that does sound conservative.

Okay, okay. One last one for me, I guess, Martin. Can you talk about -- I know Canada was delved into in terms of the revenue deltas and what to expect here. I was wondering if you could talk a little bit about just the U.S. revenue trends as we move forward here on a flattish rig-count environment. If you think about some continued pricing degradation on the stim side, I guess if we assume that's about 40% of your North America revenue stream is stimulation right now, but you talked very optimistically, I guess, about your other product lines, non-stim-related. How do we think about top line growth in the U.S. here relative to rig count? And also, just what's still going on in terms of the tough Pressure Pumping market in general?

I don't want to share an absolute revenue projection for U.S. onshore. But I think there's a, like I said earlier, a real bias towards this absorption of technology into these basins. And we can't keep up with the demand on some of those products and services at this stage. Now there's obviously a limited amount of pricing of power, given the economics that the customer's experiencing and so forth, but we don't have -- I don't have any worries about where our products sit relative to our competitors. And our portfolio, especially around production Chemicals, Artificial Lift and Completions, I think, is about as oily as you're going to find. And we're seeing strong pull in all of those. And then the other element of North America that I don't think has come out yet on this Q&A still is around the Gulf of Mexico. And we've got a couple drivers there. Pricing is getting better. Utilization is getting better. And the mix of the well types is getting more favorable for us and certainly well into '13. So yes, flat rig count is not generally a good indicator for our business, because it -- and all it takes is an extra wireline truck or an extra motor somewhere to start to bring prices down. That's just the nature of this business. We're generally -- we don't like to see a balanced condition. But when you actually drilled a layer below that and say, "Well, what can the AutoTrak Curve do versus a regular MWD motor system?" that's a whole different conversation with the customer, and some of those products, like I say, are in pretty tight supply. So we feel pretty optimistic, granted, cautiously, because there's still a lot of uncertainty out there. But we feel pretty good about our pricing on our other products and services and our mix.

Your next question comes from the line of Ole Slorer with Morgan Stanley.

Martin, where do you think you stand at the moment or where do you feel you stand on the integration of BJ Services and its reorganizations, particularly within North America?

I think we stand very well. The integration was never in question. As we reported on previous calls, we delivered the economic synergies with regards to the cost removals early on, back in '11. And in terms of our cross-selling and working as a team, the blue wellbores, we call it, is stronger than ever in terms of leveraging both products and services. As you'll recall on the last call, the issues we had around the Pressure Pumping product line didn't have anything to do with its products, its services or its well side execution. It just had some tactical decisions that we made around where we were operating, contract position and so forth. And we've taken actions to resolve that. So the integration was, in all aspects, I believe, very good and pretty much essentially complete.

So with that, can you share anything about where, let's say, leading-edge pricing is in Pressure Pumping relative to your backlog and relative to whatever else you can squeeze out of your cost side and bring that in the context of the improvement in the other segments? I was just sort of trying to get a feel for the cross-currents that we have to think about going sequentially to the third and fourth quarter.

Well, what I'll say, Ole, is kind of what I said earlier. On the pricing front, it's kind of hitting -- it's sliding in on a -- it has further to probably go in some of the gas basins, but it's decelerating. And it's obvious, I think, where it's going to land as capacity is rolled out. Do we have some downside risk in some of the oily basins? Yes. And it's probably weakening in some. And then you have one basin that's NGL-driven where I'd characterize it as a knife fight right now in terms of pricing. But overall, I'm a little bit more optimistic about where this is going to land than I was 1 quarter or 2 ago, and perhaps part of that is just our greater understanding of the business as we've -- as our teams have gotten their hands around it. That doesn't -- as Peter highlighted, the improvement in utilization that we had in our prepared commentary but also the supply chain benefits will come more into Q4 and into next year. So that's about all I can say on it.

This knife fight or this covenant with respect to downside in certain oil, is that Pressure Pumping-centric? Or does it that also extend to rig count lift [ph]...

Only Pressure Pumping, Ole.

Only Pressure Pumping. Everything else is holding together?

Yes, yes, correct.

With respect to the unconventional opportunity outside North America, where do you see the biggest opportunity for Baker Hughes?

Saudi north gas fields, China, and hopefully, Argentina. In that order.

Your next question comes from the line of Mike Urban with Deutsche Bank.

Appreciate all the detail, and it also helped [ph] us work through North America. And so I think it was pretty clear on kind of what the averages should be for the second quarter. I just wanted to think about it on a leading-edge basis and see if I'm kind of understanding the different moving parts. So guar, obviously, on a leading-edge basis, down quite a bit. You've had some success on the cost side and the self-help initiatives. Your costs are down, and you've got a full quarter benefit of that kind of going forward in the second -- later in the second half and later this year. Utilization sounds like it's up. And as you talked about, price down but kind of decelerating. Does that -- can I take that to mean that at the leading edge, your pumping margins are bottoming here? And I know there's a lot of uncertainty going forward, but as it stands today, are we kind of seeing those bottom out, netting out all those different parts of the equation?

Going into Q3, the answer is no because you talked about leading-edge, but we still have inventories of guar that are going to drive our guar costs up sequentially. And I think that's a big factor that's probably going to drive margins down into Q3. And then only when we start working through that inventory will we see some benefit. And I think all the other factors of self-help versus price and all that, they feel like they're possibly getting into balance.

Right. Okay. So yes, I was just trying to kind of mark everything to market. So if you took -- if you just were running through today's guar price and the current cost structure, current utilization.

And I am referring to onshore U.S. Canada, it's just getting started, and pricing is more uncertain, almost, there, because we're starting to feel it. So...

And your final question comes from the line of David Anderson with JPMorgan. John David Anderson - JP Morgan Chase & Co, Research Division: Some more, I guess, in terms of a bigger-picture question for you. Just curious how your view on the Pressure Pumping business overall has changed over the last 12 months. Is this a business that you really want to grow? Or are you viewing it more defensively as a means to bring in other service and products?

No, no, we don't see it as a defensive business. It's a tremendous business, and it's so critical to being -- it's part of the fabric of who we are. It's a core business for us. I mean, if you define the company, I mean, we really revolve around Drilling, Completions and Pressure Pumping now. And all of those play so importantly to our customer. I mean, there's so much rhetoric, David, around unconventionals. I mean, you can't pick up a publication today, whether it's The Economist or The Journal or TIME Magazine or The New York Times, and they're not talking about the unconventionals. I think what's lost a bit is that the companies like ourselves and our bigger peers were the manufacturing companies of those unconventionals. I mean, we produce the wellbore. And you can't be in that business without having a leading organization like our Pressure Pumping business. And as we highlighted and shared with you guys as transparently as possible, we had some technical challenges -- I mean, tactical challenges, sorry. And I think some of you have met the new leadership team of that business. And they've delivered great results in a accelerated fashion, which is our -- the Baker Hughes way. And you couple that with things like AutoTrak Curve, FracPoint. And I go home at night, I can't think of a better business to be in, and Pressure Pumping is one of those. John David Anderson - JP Morgan Chase & Co, Research Division: Okay. In terms of your view on the rig count saying kind of U.S. market going to be basically flat in the rest of the year. We're not really seeing any more capacity being added. You said you're not adding more. It sounds like we're hearing that from everybody else. Is that enough to balance the market? Is a flat rig kind of enough to balance the market?

Yes, it is, David, because -- and in follow up to your earlier question, our drilling group, with the Curve, continues to drill longer and longer laterals faster. FracPoint guys and girls develop tools like FracPoint, DirectConnect and so forth, which give you greater and greater density for that lateral. And guess what that turns out? Just like you saw on our prepared remarks or heard in our prepared remarks, the number stages per day per fleet are going up. So a flat rig count, given that we're drilling longer laterals and more stages per lateral in addition to our customers down-spacing in some of these fields, yes, a flat rig count is fine. John David Anderson - JP Morgan Chase & Co, Research Division: Just one last quick question on...

With discipline on how much horsepower is added, of course. But hopefully, that will -- hopefully, everybody's kind of learned their lesson. This wasn't a -- this issue around Pressure Pumping wasn't a customer lack of demand. It was a supply-driven problem, and we're getting our hands around it. John David Anderson - JP Morgan Chase & Co, Research Division: Got it. And last quick question, on your rig count forecast, as you're looking out there, we're hearing some concerns out there in the Bakken about differentials are kind of blowing out there. I mean, I think they're kind of bouncing around quite a bit. I'm also curious about just kind of maybe NGLs versus Permian versus Bakken. How are you thinking about kind of just generally speaking about how those kind of play out here and how sensitive they are to commodity prices? What are your customers telling you now? Because I think that's a big concern everybody has out there, is there another shoe to drop?

Right. I think the shoe is dropping in South Texas, no doubt about it. And in terms of the Bakken and the Permian, I'm a little bit more concerned about the Bakken than I am the Permian, even though the Permian, I think, has a greater degree of NGLs. It's a -- that differential in the Bakken is -- I'd say that depending on the player and what his core property is, average of, say, a $15 differential. Probably as long as it's 85-plus in the Bakken, we're fine. I think if it gets close to 80, people start getting a bit nervous. And if it goes below 80, you could start to see -- for a sustained time, you could start to see some rigs coming off. But the whole NGL situation has unfolded so fast, David. I mean, it's down, what, some of it 40% year-on-year? And most of that is in the last 3 or 4 months. So I think we still don't know, to your question around the shoe dropping. But it's already dropped in South Texas. That's for sure.

That concludes today's presentation, and thank you for your time today.