Good morning. My name is Lechae, and I will be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Second Quarter 2011 Earnings Conference Call. [Operator Instructions] Thank you. I would now turn the conference over to Mr. Adam Anderson, Vice President of Investor Relations. Sir, you may proceed.

Thank you, Lechae. Good morning, everyone. Welcome to the Baker Hughes Second Quarter 2011 Earnings Conference Call. Here with me today are Gary Flaharty Clarity; Chad Deaton, Baker Hughes' Chief Executive Officer and Chairman; Martin Craighead, President and Chief Operating Officer; and Peter Ragauss, Senior Vice President and Chief Financial Officer. Following management's comments, we will open the lines for your questions. Reconciliation of operating profits and non-GAAP measures to GAAP results for historic periods can be found on our website at www.bakerhughes.com in the Investor Relations section under Financial Information. Finally, I must caution you that any company outlooks discussed this morning 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 a full discussion of these risk factors, please refer to our annual report 10-K, 10-Q and in particular, the forward-looking disclosure in this morning's news release. With that, I'll conclude our discussion of the administrative details and turn the call over to Peter Ragauss. Peter?

Thanks, Adam. Good morning. And before I get started, let me just take a moment to say a big thank you to Gary Flaharty. For more than 14 years, Gary had skillfully shared the Baker Hughes' story with the investor and analyst community, having prepared an excess of 56 earnings news releases. So on behalf of the entire Baker Hughes organization, we thank Gary for his service and wish him much success in his new role here at Baker Hughes. Thanks a lot, Gary.

Thank you.

Switching gears to the financials. This morning, we reported net income of $408 million, or $0.93 per share. This excludes the Libya charge of $70 million, which would be $0.16 per share before and after-tax. This charge is associated with increasing reserves for doubtful accounts, inventory and certain other assets as a result of ongoing events in Libya. Including these expenses, on a GAAP basis, net income attributable to Baker Hughes for the second quarter 2011 was $338 million, or $0.77 per diluted share. Revenue was $4.74 billion, up 41%, or up $1.37 billion compared to a year ago and up 5%, or $216 million, sequentially. Adjusted EBITDA was $1.02 billion, up 85%, or $469 million compared to a year ago and up 7%, or $63 million, from last quarter. To help your understanding on moving pieces, I'll bridge Q2 last year EPS to Q2 '11 EPS. GAAP EPS a year ago was $0.23 per share; add $0.13 for acquisition-related expenses in Q2 last year; add $0.02 for the impact of the lower tax rate this quarter, offset by a higher share count; expect $0.05 for higher corporate cost and net interest expense. Operations and one extra month of BJ services this quarter compared to a year ago added $0.60, which brings us to $0.93 per share. Last check, $0.16 for the Libya charge. That brings us to $0.77 per share on a GAAP basis. Bridging these sequential quarters, GAAP EPS for last quarter was $0.87 per share. First, subtract $0.02 per share for the combination of a higher relative tax rate, higher share count, higher interest and lower corporate expenses this quarter. Operations added $0.08 per share, including the impact of the seasonal breakup in Canada. Last, the impact of Libya was $0.16 per share, which gets us to…

Thanks, Peter, and good morning, ladies and gentlemen. Prior to delving into the operational update, I'd like to take this opportunity to tell you how we are better positioned to compete as a result of the integration of BJ services. Let's start with North America operations where the proof our strength is clearly demonstrated by the capture of $400 million in new multi-service contracts during the quarter. These winds were primarily driven by the integration of our pressure pumping, horizontal drilling and completions technologies. The timing of combining the BJ Services products and services into Baker Hughes couldn't have been better. We're now very well-positioned to capture an increasing proportion of the unprecedented levels of activity we're seeing in the unconventional shale plays. Near term demand continues to outpace supply, but not only in pressure pumping but also directional drilling and completion services. Sequentially, revenue improved in U.S. Land at a pace more than twice that of the rig count, which speaks to the growth in both the service intensity per rig as well as the emerging power of our fully combined organization. The service intensity per rig in the unconventional markets is being principally driven by 3 forces. First, rigs are becoming more efficient as we work with our customers to address their drilling challenges. As such, we are routinely posting improvements in rate of penetration and decreasing time from spud to total depth. Second, horizontal drilling technology continues to improve. Baker Hughes has been a leader in pushing horizontals even further, with 10,000-foot laterals now considered routine in some parts of the United States. And as AutoTrak Curve, a technology we introduced last quarter, gains further market penetration, we expect this trend a longer lateral length to continue. And last is the number of stages per well. Reservoir…

All right, thank you, Martin. Good morning, everyone. I'd like to start by quickly highlighting the progress we've made against some of the key targets that we laid out earlier this year to all of you. First, our international margins continue to improve. We're making solid progress towards exiting the year with mid-teen international margins. This has been a result of trimming our cost, growing our business and improving our overall operating efficiency. Certainly, there's more work to be done, but we're pleased with the steps we've taken so far, and our current trajectory is definitely in the right direction. Second, as we said before, we expect to deliver superior margins in North America throughout this cycle. The seasonal breakup in Canada did provide some marginal headwind this quarter, but activity will improve over the next few quarters as the fundamentals in this area are particularly strong. We remain confident in the underlying strength of the U.S. market and are encouraged by the ever-increasing number of unconventional plays our customers are asking us to help them exploit. Our new technology, including AutoTrak Curve, In-Tallic disintegrating frac balls and extended stage FracPoint systems are all delivering results in the first stages of their commercialization. And we continue to be encouraged about the impact Baker Hughes' technology will have on this very important market. Third, we told you we intended to be the leader on offshore markets. Let's start with the Gulf of Mexico where, as you know, the deepwater remains a work in progress for all of us. Clearly, the pace of permits remains lighter than the industry had hoped for. However, we're seeing progress on this front and like our customers, we continue to be committed to this very important basin. The deep gas on the Gulf of Mexico shelf…

Thank you.

And with that, I'll turn the call over to Adam, and we'll take some questions.

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

And your first question comes from the line of James West with Barclays Capital

Chad, in your comments around international pricing, you sound a little bit less optimistic than one of your major competitors was on Friday when they talked some price increases coming through at the end of the second quarter. I was wondering if you could, I guess, highlight maybe perhaps your differentiated view versus them on pricing? Are you being more conservative? Are they being more aggressive? Or is it more just a question of where they play in the market?

No, James. I didn't mean to not sound positive on pricing because we are starting to see movement. We saw a little bit of movement in the second quarter. Some of it -- I mean, this obviously is market-by-market, region-by-region and business-by-business. But we saw a little bit in the second quarter. We submitted quite a bit of price increases. Some has been awarded, some we were declined on, and some will not kick in till probably Q3, Q4 and into early 2012. The momentum is definitely building. There's no doubt about it. Stronger in some markets than others, but I don't want to sound negative on pricing because it is building.

Okay, understood. In which markets in particular are you seeing the most pricing momentum at this point?

Well, I don't want to give details because it's our specific markets, which I'm sure they wouldn't want to tell us where they're increasing pricing either. But we're seeing a little bit in the Far East. We saw some in a couple geomarkets in Latin America, and we see a little bit in the Middle East. Not so much in Europe yet, but it's beginning to get the feel in Europe. So I think those are mostly the markets where we're seeing it. It's just like we started to see it about 3 quarters ago in North America and continue to build, and that's what we're starting to see internationally.

And your next question comes from the line of Bill Herbert with Simmons & Company.

A question with regard to Canada and how we think about that. First of all, Martin, can you give us a sense as to what the revenue decline was quarter-on-quarter in the second quarter? Was it greater or less than 50%?

This is Peter. It was greater than 50%.

Okay, and so when we think about the third quarter, do we think about capturing about half of what was lost quarter-on-quarter in Q2? How should we think about that, Peter and Martin?

Probably similar between 1/2. Probably around 2/3 recaptured.

Okay, great. That's very helpful. And then, Martin, with regard to the advent of sliding sleeve technology and the traction that it's gaining U.S. onshore, historically, the way we thought about this what that it was an application that was being well-received in markets with meaningful weather windows: Bakken, Canada, et cetera. How should we think about sliding sleeve going forward? Is it going to gain significant traction beyond the weather-sensitive markets? And if yes, why?

I would say that it has maybe modest growth beyond the markets you did highlight. But I think the point here that is maybe lost a bit is that this technology continues to evolve rapidly itself in terms of efficiency. Everything from running it and to executing it. Of course, you're familiar with the clean up process of the In-Tallic technology?

Yes.

And as well, as I kind of hinted at, there's -- not every customer completely accepts its application yet, relative to the more traditional. So I don't want to tell you exact market absorption rates, but there's a substantial amount of opportunity in the existing basins for this technology to still convince, let's say, offset customers of the value it provides. So new customers as well as evolving technology, I'd say, still has a huge amount of potential for the product line.

And the differential in time per stage, plug and perf on average, I think you guys have said has 5 hours per stage; and sliding sleeve, 1 hour per stage? Is that correct?

More or less.

Okay, got it. Last question for me, Martin, same question I asked you last call, and that's the pace of absorption and delivery with regard to new frac capacity that's been ordered. Are we still on a run rate of 40,000 horsepower every 6 weeks?

Yes, probably picking up a bit. We were a little bit back-loaded just given the integration of BJ into the company. So unlike our, let's say, our peers, we probably had a more back half-loaded CapEx plan with pressure pumping. So that's a safe number.

So the amount of horsepower that's going to be delivered second half for 2011 versus what's been delivered first half, is it -- I understand that's more. Is it modestly more, or is it more than trivial into the difference?

It is probably more than trivial.

And your next question comes from the line of Kurt Hallead with RBC Capital Markets.

Chad, a follow-up question here on the pricing power. In the U.S. first, can you just give us some general handle on where you're seeing it increased the most outside of pressure pumping? And then what product areas do you think are still lagging?

Drilling systems clearly has a lot of price traction right now. Bits are okay, but as we know, bits in the U.S. don't require the same capability or technology challenges in the shales as they do on the sands and others. I think fluids. We're probably still lagging a little bit. There's more room to go there. And completions are clearly have a lot of traction on price. Complex completions.

Okay. Can you guys talk about the pricing improvement on the international basis going out into next year? We're starting to see some signs of it now and then going out into next year. How do we think of the flow-through that on the P&L, generally speaking -- right? Because you have, I think, a number of projects that continue to roll off. So do you think you get like 1/3 of the pricing benefits next year? 1/2 of it? 2/3? How do we think about pricing power for international projects going into next year?

Well, I think you still have 1/3, 1/3, 1/3 of type contracts roll over, Kurt. I don't think the long-term contracting in international is going to go away. So at minimum, I think you're going to see some improved pricing on 1/3. But we are -- as we said in our comments, we are going in, even on existing contracts and pushing price on existing contracts, especially on some of the directional type work because tools are getting tight. Everywhere you can feel it. So it's actually a little over 1/3, could roll into early 2012.

Okay. And than lastly, just wanted a little -- looking for some clarification. You mentioned some increased costs to meet the new rigs for deepwater Gulf of Mexico. I haven't really heard that from the other major players yet, so what kind of costs are you looking at?

Well, I think it's too early to try to put an actual number dollar on it, Kurt. What we're seeing is that clearly, come the end of November, the OEMs are going to require certain minimum standards to be met offshore, compliance standards. And this means -- and we're seeing it in some of the audits that are going on with our customers as they visit our facilities or BOEM or clients audit the rigs that you're on. So we are being proactive in this area. We know it's coming. We've seen it happen in the North Sea, back after following the Piper Alpha disaster. And for a period of about 1 year and 18 months, you see increasing regulations and standards being set. So we are just trying to get ahead of the game to make sure that, come November 15 when some of these regulations are rolled out, we are well in line and not any surprises for us. So we can't really quantify yet, but we clearly have picked up on our training and certification of people and making sure our systems are in place to handle it.

And your next question comes from the line of David Anderson with JPMorgan. John Anderson - JP Morgan Chase & Co: Just sticking on the same subject of the Gulf. I think in the past you said you're on something like 40% of the deepwater rigs out there. Permits, obviously a huge issue. Everybody's talking about -- how are you guys planning your business around this over the next 12 months, especially amid visibility? I mean, where do you guys think you're going to be a year from now in terms of equipment, services, people? You think you can be back 50%, 75% back in normal? I mean, how does this go through your mind?

Well, first, it all starts with the government and the permitting. The clients looking at the next 2 quarters, clearly through the end of the year, have already assigned work on the rigs that are coming in. So I think we are at, what, 16, 21 rigs in Q2, and it's going to 24 rigs in Q3. Here's an ongoing shift with half of those on work or half of them drilling. That increases quite a bit in Q3 and clearly more in Q4. That's subject to getting the permits on all of them. Some of them have permits, some don't have. We know what rigs we're assigned to in Q3, Q4. We see a nice build through Q3, and a very nice position in Q4 as Martin highlighted in his comments. So that's our planning in terms of people and equipment needed. So in a sense, this thing is kind of ramping up fairly slowly. It allows us the time to go ahead and try to get the equipment built and assigned and cleared to get the people back on board. We brought all of our people back that had been assigned outside the Gulf, the deepwater, over this last quarter, quarter and a half. So they are now back in place. I don't know, Martin, do you have any comment you want to add to that?

Yes, thanks, Chad. David, I'd say that, to follow up on Chad's comments, there's 130 or so well locations identified in the lower tertiary over the next several years. This is an enormous amount of spend. Our customers, the key customers are committed to it. No one wants to speculate on the exact timing or the way the government will respond, but we are here to service our customers. I can tell you that the amount of conversations regarding these complex completions, all the way into 2013 given the type of technology that's required and the conditions of these wells, are probably at a record pace actually. So are they out there drilling to the density we'd like? No. But is the work being done to prepare for it, including, as Chad mentioned and I mentioned, preparing for the stuff, this work at a much higher standard of performance, is under way. So how are we planning for it? We're optimistic and we're confident that -- we're not going to try to predict exactly, but we're confident it's going to follow through. John Anderson - JP Morgan Chase & Co: So with all your people back in the Gulf, presumably your margins in the Gulf are a little bit of a drag right now. Obviously, Canada was a big drag. And Peter, maybe you can just kind of quantify for us how much that impacted your margins? But I guess my broader question is, Chad, you were talking about superior margins in North America, but your margin progression seems to be coming at a slower pace than your competitors. Obviously, there isn't any reason for that to continue your product line, your strength of your completions business. So how does that -- how do you guys close that gap? Is that something that closeable over the next 12 months? Is there any reason you think that shouldn't close?

I'm not concerned about our North America margins bouncing back. We're the biggest player in Canada. I don't think we -- we're not going to outline exactly what that hit in Canada was, but it went from 587 rigs to 187 rigs. That's a 400-rig drop, and that hit us pretty hard. And as we said, Gulf of Mexico, what rigs did go back? We had a mix issue in that. We were not necessarily on some of those rigs that went back, but we're clearly on them in Q3 and indefinitely in Q4 because like I said, this work has been awarded. We know who's going to be on which rig in Q3 and Q4. So I think the Canada mix definitely hit us this quarter. Gulf of Mexico hit us a little bit this quarter. And we're still catching up, as Martin said, on the pressure pumping side. Technically, we’ve had BJ 2 quarters now. We are clearly seeing a pull through both ways from putting pressure pumping on some of our completions, complicated completions, as well as the other way around now. So I'm not worried about U.S. margins. We also said that we would be a leader through the cycle, and we've got a pretty good chunk of our business in North America. It is tied to the production side, the ESPs and the chemicals. So when things are booming and rig count is accelerating rapidly, we're probably not going to have the top margins in that area. But I have no doubt when things soften, we will clearly have the top margins during the weaker period. So as we said, we want to be able to lead throughout the cycles. But I'm not concerned with North America margins. They are there, and they'll be back in Q3, Q4. Will they be at the very top? Maybe not with our production side influence. But we'll be up there, very, very competitive.

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

Just following up on that last point. So if we look into the fourth quarter, do you see that, for North America, that you will be -- and you've come to benchmarking yourself against the industry it appears in the fourth quarter, do you expect to kind of meet your targets at that point? Just to clarify that once and for all and be -- I mean, that's the fourth quarter, which is, let's assume this is in Canada, clearly not like it first quarter, but decent? So do you think you will be on a sequential year-over-year -- sequential and year-over-year revenue growth and margins be where you want to be? Where you highlighted?

Yes.

Very good. You talked about the Gulf of Mexico coming back, let's presume also very high margin work compared with the onshore. But could you talk a bit about the timing of when this work was awarded to you? What's the timing between when you are given a contract and when the rig mobilizes? In other words, when did you win this stuff in the third quarter?

Yes, this is all over the map, Ole, because a lot of it depends on when the rig is ready. And then clearly, it depends on the permit that the clients are finishing up on, on the permit and allowed to get back to work. But we see, as I said in Q4, from what we've seen and what the clients have told us and what we need to be geared for, Q4 will be the first real big improvement for us. Q3 will be a little better, and Q4 is much better in the Gulf of Mexico for us.

And could you help us a little bit with a generalization on when that Q4 work was awarded on average? Give us a little bit more color?

Last quarter or early last quarter, clients started lining up. I mean, we just moved on 3 -- 2 drill ships in the deep semi in early July. That just went out. And that work was probably awarded, what, Martin, 4 months ago?

Yes. Ole, it's all over the map. But we're in customer offices now with contracts that are awarded, planning the well, and the well won't spud until 2013. These investments our customers are making are just incredible, and the technology requirements, the amount of manpower and the thought leadership so to speak. So it's hard to generalize. But I'd say, probably from award for actual -- I think a safe number might be 6 months.

Okay, so the work that was carried out in the second quarter, was that for the most part awarded post-Macondo?

Post-Macondo, yes.

Your next question comes from the line of Matt Conlan with Wells Fargo Securities.

Guys, I wanted to ask about the North Sea. One of your competitors said that they thought that the change in tax regime there was having a negative impact on the customer commitments to new business. Have you seen anything on the U.K. side that confirms that?

No, we haven't, Matt. But we've been saying for quite a while, our people said they don't think that's a 2011 event for us. 2012 may see some things happen. Too early to tell you, but we actually had a pretty decent order in the U.K. It didn't affect us.

Okay, great. And turning back to the U.S., Schlumberger gave some incremental margin improvements in the first quarter to the second quarter on U.S. land. Are you able to give kind of the same kind of apples-to-apples difference between first quarter and second quarter margins for U.S.?

Peter?

Well, we had pretty strong incrementals in U.S. land in Q1 to Q2, which are sort of 40%, 50% range. And revenue growth, you can -- similar to the peers. So U.S. Land, we're all doing pretty well.

Okay, okay. So the bogey that you put out there, that you were more than 2x the rig count growth for revenue growth, I mean, that's around 12%, 12.5%. But it seems like you did actually significantly better than that.

Yes, we did better than that.

Yes, we did. U.S. land was not our issue in the second quarter as we said. It's Canada and a little bit of Gulf of Mexico.

And your next question comes from line of Scott Gruber with Bernstein. Scott Gruber - Sanford C. Bernstein & Co., Inc.: Martin, you mentioned that the number of jobs with multiple products and services being sold in North America doubled for you over the past 3 quarters, I think it was if I heard you correctly. It sounds like you're taking material share in that market now with BJ Services under your umbrella. Is that true? Do you think you are taking material share in the package service market in North America?

Correct. I think we're taking some share, I don't know if I'd want to say material. It's really providing an overall solution for the customer. But as Chad highlighted as well, I mean, all the key products or service lines in U.S. land right now are outside of maybe a couple. Depending on the basin, they're sold out. So share gain is not objective by any means. And the other thing, Scott, that we didn't define, but since you asked, when we say multiple services, it's 3 or more discrete services on a well site. Scott Gruber - Sanford C. Bernstein & Co., Inc.: Okay. And I am not sure if you have the full market data for just how big the kind of package service market is as you define it based on 3 or more services. But do you feel like your share now with some incremental gain is more on par with your size? Or do you feel like there's some more running room there?

Oh, no. It's doubled. I could tell you, it's still less than half of where out there, let's say, with the frac fleet. We've got a lot of headroom in this category. Scott Gruber - Sanford C. Bernstein & Co., Inc.: Okay, great. And then just turning to Latin America, just wanted to hear some detail on the slight sequential dip in margins there. As you provided some color, was it cost inflation or just mix? Any detail would be great.

I wouldn't read much into that, Scott. It's really just a little bit of mix.

Your next question comes from the line of Joe Hill with Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Chad, how would you handicap your chances of hitting your 15% international margin guidance a quarter early this year?

We'll stick with our original plan. We're going to hit 15% when we leave the end of the year. So we're not going to change our plan, Joe. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And then we've heard from both you guys and some others that drilling and, in some cases, wireline, is kind of leading pricing. If you rank your product categories in North America, are drilling systems in excess of pressure pumping now and pricing momentum?

I would say yes, but Martin, you want to confirm that?

Yes. You're right, Chad. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes. Okay. And then you guys talked a little about doing some jobs for YPF in the Neuquen. I have been thinking that basin was a sub-100,000 horsepower basin total. When you look out over the next several years, how big do you think we can get there?

Well, I think if you look around the world at potential shale plays and customers I've had lunch with or talked to who are sniffing around down there, I think Argentina is exciting, as what people were saying for the U.S. And you're right, I mean, I noticed in our comment at one point we said our first frac in the geomarket, and that's not true. We've been fracing there. BJ's had a history in Argentina for quite some time. It's our first horizontal frac in that area, horizontal share frac. But the one thing about Argentina, horsepower can be added there fairly easily. And a lot of it is because you can take U.S. horsepower and move it down there, a U.S. tractor-trailer type horsepower, which is not the case you can do on a lot of places around the world. So if it takes off, the capability of building horsepower in the U.S. is clearly there, and people can just -- eventually, we'll start moving horsepower down there. We'll build it easily for the Argentina market. Argentina is more a challenge in just terms of some of the government regulations and unions and other type things. And I think that, to me, is what's got to play out before people invest heavily down there.

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

Martin, my question for you is I know, I guess, historically, the approach in the U.S. pressure pumping business for Baker has been to stay relatively short as it relates to your contract structure. I'm just curious with the incremental adds that you continue to discuss on the call earlier, what's the thought process here to perhaps getting a bit more term contracts in place on the U.S.? Maybe you could share with us what kind of the split is between longer term and short term as we think about your U.S. pressure pumping capacity right now.

Okay, Bill. First of all, when we say history, of course we're only talking about 9 months, right?

Sure.

All right. So we’re a little bit a neophyte at this. Our sense is that we still like to stay one, call it spot market, but flexible. Do we see an increase with customers wanting to commit a little bit longer? Depending again on the portfolio of services that we're awarded, depending on the depth that we get into their business in terms of well planning or even better field development planning, we'll have those conversations. But at this stage, I don't think we've moved the needle materially. In fact, I know we haven't from long-term to from short-term.

Bill, this is Chad. Let me just add something to that. Martin talked earlier about some big wins on these solutions, total packages with multi-services. I think that is the change we're seeing in this industry in North America, where a client is awarding a multi-product line, as Martin said, reservoir completion type package and fracing. That tends to be being awarded now on a year-type basis with a -- in a lot bigger package. So in the individual call out pressure pumping type thing where they're only looking at a year or 2 contract for just pressure pumping, I don't think that's happening. But the multi-package projects tend to be starting to out a little bit longer.

Okay. Peter, my question for you as it relates to the third quarter margin in North America, given your earlier comments, is it reasonable to think, as we just do the math here, that third quarter '11 margin could approach back to the fourth quarter '10 margin that we saw in North America? Is that a reasonable type of inflection to be assuming for the model at this point?

Refresh my memory on Q4 North America...

So you were close to 22% in the fourth quarter in North America of last year.

Yes, it's highly possible.

Your next question comes from the line of Angie Sedita with UBS.

Chad or Martin, can you give us some comments on your Iraq operations, first on your margin progression versus your goals? And second, I believe you were the official low bidder on 2 Iraq IPM projects. What is the status of these awards? I believe you were potentially waiting on government approval. And if that is awarded, when would that work begin?

Martin, you're going to take that?

Yes. Angie, as I said in my comments, we're quite happy with our progression. As you know we simply bumped up the production side of this. We have been on the sidelines a bit based on the risk profiles. It should be not a surprise to anybody that initiating these contracts there can be very, very challenging, depending on the scope of the work that was outlined. You're correct with regards to the information you have on some projects, but I'm not going to stipulate as to -- and we haven't really been public on those yet, because we don't have any -- probably much more information than you do as to the actual timing of the award. But those are big awards. But again, they have to work through the machinery within Iraq. And in terms of the margins, I can tell you that we were slightly profitable, and we expect to be moving in that direction from this point on Iraq.

Okay, okay. So is it fair to say you are waiting through the government process before you make any commentary on the awards?

Yes, ma'am.

And then, secondly, you obviously had some pretty impressive incremental margins in Europe, Africa, Russia at 74% with margins moving from 11.8% to 14.5%. Was that driven by a specific country, region? What occurred in the region?

Well, I think one, Africa continue to turn around story in getting better. So that helped, contribute quite a bit. And we did have, as I mentioned, a good U.K. and Norway quarter, and Continental Europe is as well. And Russia continues to improve. So I think it's all the way across the board. The only area, Angie, that was probably a little bit weak is all of those areas comparatively was probably the Kazakhstan, Azerbaijan area where things are a little softer. But everything just stood across the board and improved in Europe.

West Africa and Algeria particularly, to give you some more detail, Angie.

Okay, okay. Well, you are one of the few that are seeing good numbers in Algeria. And then finally, Russia, you had a nice ESP award in the region. Thoughts on the activity outlook for 2012? And could you see pricing in the region next year as well?

Yes. If you recall, we thought Russia would one of the first areas internationally where we start to see some price movement. At the early of the year, it was looking pretty decent. But that's kind of gone flat. I think Q3 pricing will be flat. Q4, we start to see a little bit of improvement. Now that being said, activity shows a nice ramp in Russia in Q3. And then Q4, Russia will be ending the year, pretty decent position. We just moved, beginning of this Q3, on 3 big IO projects, integrated projects, that just got kicked off, which will be contributing heavily in Q4. And I think, like I said, activity is improving and Russia. And probably, Russia will be a 2012 price inflection point or price change point.

And your last question comes from the line of Rob MacKenzie with FDR. Robert MacKenzie - FBR Capital Markets & Co.: I wanted to explore with you guys a little bit more of the sliding sleeve technology in general and FracPoint in particular. There have been some that have criticized it -- more generically, is the sliding sleeve technology as producing poorer results than to the plug and perf. And then there's been other anecdotes where it outperformed. Can you give us a feeling for how much of that might be the technology itself in individual applications or the plays? Or how should we think about how the sliding sleeve technology will proliferate and where it's most applicable?

Okay, rob, this is Martin. Let me take that. I don't understand the criticism of it, so I'm not going to go there. The absorption in the market I think kind of -- should put those arguments to bed. Customers would not be continuing to repeatedly use it if they weren't seeing differential performance. And I would not say that I could identify any issues with the technology itself, other than it continues to evolve and be more applicable and more reliable. To me, and it gets back to what I said, what Chad has been saying for a long time, I gets down to the reservoir characterization to begin with. How this -- where the well has landed, the type of geology, specifically. And to say that the sliding sleeve technology, which allows obviously the customer to put a lot more fracs on something that has extremely low permeability, to say that it doesn't have increasing application is beyond me. I don't understand that argument. And so as I mentioned earlier, the 40-stage, the In-tallic balls, the new FracPoint direct connect, which we'll be launching shortly which has built-in nozzles to get the fracs more initiated and more focused, hold a heck of a lot of promise in not only U.S. land, but other parts. As we mentioned, China and Argentina, specifically. Robert MacKenzie - FBR Capital Markets & Co.: Okay, great. That's very helpful. And I guess as a follow-up to that, when you aren't able to convince a customer to use it, what is the pushback you typically hear? And how do you address that?

Cost. Money. Robert MacKenzie - FBR Capital Markets & Co.: So it is a trade-off between the benefit and the incremental cost to do it?

That's right.

All right. Thank you, Rob. And thank you, Chad, Martin and Peter. I want to thank all of you -- all of our participants this morning for your time and your thoughtful questions. Following the conclusion of today's call, Gary, Alexey and I will be available to answer your calls. Once again, thank you for your participation.

Thank you for participating in today's Baker Hughes Incorporated Conference Call. This call will be available for replay beginning at 11:30 a.m. Eastern, 10:30 a.m. Central and will be available through 11:00 p.m. Eastern time on Monday, August 8, 2011. The conference ID number for the replay is 77447493. The number to dial for the replay is (800) 642-1687 in the U.S., or (706) 645-9291, international. You may now disconnect.