Good morning. My name is Dennis, and I will be your conference facilitator. At this time, I would like to welcome, everyone to the Baker Hughes Third Quarter 2010 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Gary Flaharty, Vice President of Investor Relations. Sir, you may proceed.

All right, thank you, Dennis, and good morning, everyone. Welcome to the Baker Hughes Third Quarter 2010 Earnings Conference Call. Here with me this morning are Chad Deaton, Baker Hughes' Chief Executive Officer and Chairman; Martin Craighead, President and Chief Operating Office; and Peter Ragauss, Baker Hughes' Senior Vice President and Chief Financial Officer. Following management's comments this morning, we'll 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. In addition, this morning, we're also including a slide presentation with our webcast. Slides are available on the Investor Relations homes page at bakerhughes.com. Finally, I caution you that any company outlooks discussed this morning are subject to various risk factors. We'll try to highlight the 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 complete and 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, Gary. Good morning. This morning, we reported net income on a GAAP basis of $255 million, or $0.59 per share. Earnings per share were up $0.41 compared to a year ago, and up $0.36 from last quarter. Revenue was $4.1 billion, up 83%, or almost $1.9 billion compared to a year ago, and up 21% or $700 million sequentially. And EBITDA per share was $1.64, which was up $0.71 or 76% compared to a year ago and up $0.26 or 19% from last quarter. There were a couple of adjustments that should be made to compare results to our previous guidance. First, our tax rate before acquisition-related costs was 32.5%. Let me just point something out, that we had $12 million in tax benefits from acquisition-related costs in addition to the $12 million pretax charge, so the net result was about zero on the acquisition cost on a per share basis. The overall decrease in the tax rate is primarily due to the actions we took in the third quarter to repatriate certain foreign earnings, ultimately resulting in a reduction of current and future U.S. taxes. The Federal tax rate in the middle of our 37% to 38% guidance, the favorable impact of the lower actual tax rate was approximately $0.04 per share. Second, we've revised our estimate with the amortization associated with the BJ Services acquisition. This calculation will not be final until the end of the year. However, our best estimate is that the incremental amortization charge will now be $120 million per year, or approximately $30 million per quarter. As a result, the amortization expense associated with the step-up was $9 million lower than our guidance for the third quarter, approximately $0.01 a share. So from the GAAP EPS of $0.59, subtract $0.04 from the impact…

Thanks, Peter. Let me start with North America. Revenue increased to 71% year-over-year and 16% sequentially, matching the 71% and 19% increases in the North American rig count, a solid achievement given the negative impact of the Gulf of Mexico Deepwater drilling moratorium on activity, revenue and profit. The overall service and technology intensity of North American land drilling continues to increase. In the United States, horizontal drilling, primarily in the unconventional oil and gas plays, has more than doubled year-over-year and increased 13% sequentially. The unconventional reservoirs are demanding our best technology to deliver longer horizontals, complex completions, increasing frac horse power and more frac stages. This demand for advanced technology is in turn, driving the business and supporting both higher revenue per rig and associated higher prices. Operating margins increased 1,800 basis points year-over-year, and 400 basis points sequentially to 17%. Incremental margins were in excess of 40%, both year-over-year and sequentially, despite the lower activity in the Gulf this quarter. Before I turn to our International segments, I need to address the current situation in the Gulf of Mexico. The impact of the moratorium and the pause in drilling permit approval was about as we guided in our last conference call at $0.09. While we are encouraged that the deepwater moratorium was lifted a few weeks ago, we did not expect a significant increase in drilling in the fourth quarter. In the longer term, Baker Hughes is very well-positioned for the return of activity in the Gulf. With our two new pressure pumping vessels, the Blue Dolphin and the Blue Tarpon, we were able to offer best-in-class pressure pumping capabilities, exceeding the delivery capability of the nearest competitor by over 50%. Our current tank control vessel utilization has been high, supporting frac, gravel pack and stimulation activities…

All right. Thank you, Martin. As Martin and Peter both highlighted, our results this quarter were dominated by our performance in North America. With oil prices holding in the $75 to $80 range, we experienced strong growth in all direct drilling in both unconventional and conventional areas, and we do expect that this trend is going to continue into 2011. Drilling for natural gas has stabilized with a high percentage of the rigs drilling in the unconventional plays and increasingly on the wetter side of these plays. Together, the demand for drilling and unconventional reservoirs, whether it's for oil or for natural gas, is driving strong demand for directional drilling, complex completions and pressure pumping. Currently, we believe the increase in drilling for either oil or wet gas will offset any drilling weakness in dry gas. It is important to note that pressure pumping is a key technology for developing both types of these reservoirs. And while we have owned BJ Services since April, we really had full access to BJ in only the last month of the third quarter. So the restrictions of the whole separate quarter now removed, we can finally act on the opportunities we have to leverage our newly acquired pressure pumping capabilities in North America. Since the order was lifted, the U.S. sales teams have been working together to pull through products and services when possible. And on some cases, people and equipment are already committed, and as they roll off of the contract, we can then leverage our pressure pumping resources. A good example of what our combined company is now able to deliver to our customers is a case in Canada for a large independent. Our AutoTrak Rotary Steerable system and drill bits were used to drill a horizontal well on the Horn…

All right. Thank you, Chad. At this point, I'll ask Dennis to open the line for your questions. To give everyone a fair chance to ask a question, we ask that you limit yourself to a single question and a related follow-up question. So Dennis, can we have the first question, please?

The first question comes from the line of Bill Herbert with Simmons & Company.

Chad, talking about International margins here for a second. And recognizing that you're probably not for your planning process for next year, but just sort of conceptual journey, if you will. We're kind of hovering right now at about 5% margins thereabouts for International, and we were at close to 18% and change, first half of last year. So recognizing the benefits from supply chain, BJ synergies and expected volume gains, what do you think is a reasonable aspiration at this stage for exit rate margin sometime next year?

I think we're looking for somewhere in the mid-15% range, somewhere in that ballpark, Bill. I think you can break this down by region. Europe has not changed much, really, if you look at the margins, down a little bit. Africa has been where our challenge has been, and that's offsetting everything in Europe to defect all of work. And then the other area clearly is Latin America, where we've got another focus. Martin mentioned about some consolidation we're doing in that area to bring that -- some of the costs down in that area. We're happy with the way we're seeing Far East going. We've seen some nice gains there, both on a revenue side and some improvement on the bottom line side there. And the Middle East, we think will come back next year. So that's our target right now.

And then in a similar vein with regard to North America, margins are sort of clicking along nicely as they are for most in the industry. So walk us through, if you will, kind of on a go-forward basis, the interplay between probably a slowing rate of E&P capital spending growth, oil and liquids-rich continues to grow, offset by gas, some of which probably distills into a reasonably steady rig count from this point forward, maybe up a bit. You've got increased capacity coming. So when you think about '11 margins, on average, would we do well to kind of stay even with exit rate 2010? Or do you think it's going to be a bit better than that?

I think it'll be a bit better than that, Bill. Because we started -- obviously pressure pumping saw a lot of price improvement over these last several months. Whereas our legacy Baker Hughes businesses started to really see it towards the end of the third quarter, I guess. We started to see some tightness enough that we could start raising some prices elsewhere. So we'll see a little benefit in that in Q4. And therefore, from a year-on-year type basis, we should see improved margins on North America. And of course, hopefully, we're looking at what's going on with the Gulf of Mexico. And if we can see some rational thinking back there again, and get back to some drilling and other things then that will be a huge swing for us. Because we're big in the Gulf and we wanted to hold ourselves strong there with our people, because we believe this thing will end. And when it does, we want to be ready for it.

From sort of a incremental capacity standpoint, with all the frac horsepower that's coming, do you expect that to be sort of a headwind in the second half of next year, or earlier?

No, I think it'll be the second half. There's no doubt, it's probably coming. And we've been very fairly aggressive in terms of building out horsepower because for a period of time, BJ hadn't done a lot during the negotiations and the whole separate period, et cetera. But beginning earlier this year, we did start building horsepower while we did, because we've been needing that. But we're going through the budgeting process now, we'll be taking a look at that. We will adjust based on what we see. But there are a lot of wells behind pipe that still need frac, 2,000 to 25,000. And you'll start looking at anywhere from 15,000, we'll pick a number, 15,000, 25,000 zones per well, that's a lot of frac jobs and a lot of consumption equipment.

Your next question comes from the line of Joe Hill with Tudor, Pickering. Joe Hill - Tudor, Pickering & Co. Securities, Inc.: Chad, I think Martin touched on some of the improvements you guys have seen on the Industrial business. Can you give us a bit of an outlook there? You've kind of given us what to look for in International, but maybe you can talk a little bit more about what's going on in that particular business and what's driving the sizable improvements we saw?

Well, I think one thing that Martin said, and it's true, Q3 is usually a very strong quarter for us in that business. So I don't think we're going to see any huge drop-off. A lot of that business just tie back to refinery work. So it depends on the margins and the refining operators, what they do and when their downtime is. I think one important thing on the Industrial side, we didn't shake that particular area up much when we reorganized, like what we did on the International side with the new geomarkets, et cetera. So that pretty much was the management team that has continued to run through this entire last 12 to 18 months period. So I think they're showing a lot of stability, and they had a very good quarter. And that's a business that kind of tends to swing based on downtimes and refineries, et cetera. Joe Hill - Tudor, Pickering & Co. Securities, Inc.: So in terms of our expectation for next year, should we assume that we can hold on to some of this margin improvement we've seen? Or should we assume that the turnaround story and refinings can be fairly seasonal?

I think you could say that you could hold on to it. Traditionally, this business has been fairly stable, flat. We've talked about it in the past on our chemical side, both upstream as well as downstream, when there's tremendous swings in rig count one way or the other, this is kind of our annuity. They were pretty steady. So I think you could plan on that through next year.

Yes, this is Peter. I'd say that's right for next year. We did have particularly strong Q3, which was some seasonality in it. Q4 could be off a bit than Q3, because the other part of the business is the Pipeline Inspection business, and that has to slow down usually in Q4, which is the business we inherited from BJ. So we wouldn't expect Q4 to be a repeat of Q3. But next year, it ought to be, within a seasonality range, it ought to be a decent business. Joe Hill - Tudor, Pickering & Co. Securities, Inc.: And then finally, just more of a product-specific question, you guys have talked about the MST completion tool, and there's a few of those systems out there. I was just wondering, one, how many of these systems are available for use at any given time? And would you anticipate that usage of the tool could get large enough to actually impact availability of rig time?

Well, we're not going to disclose how many we have ready to go around the world, Joe. I think the one thing about, I think, unless I'm wrong -- Martin, you can comment on this, but I think we, by far, have the most in the ground running than anybody. So it's pretty well-proven. And I don't know, Martin, do you have any comments on it?

Well, Chad mentioned, from our data, it seems to have high leveraged to how many we've run relative to the market, Joe. The features on this tool are pretty unique to Baker Hughes. It's completely unlimited lengths of either the zone you want to cover, or the number of zones you can run. It's got a full ID opening to handle production tubing, with some very important proprietary technology on the seal elements used. So the pickup on this has been pretty rapid as far as its materiality going forward. I don't know at this stage, but we don't see it slowing down, that's for sure. Joe Hill - Tudor, Pickering & Co. Securities, Inc.: And Martin, would you like to see one of these on every rig you guys touch?

Given the pricing on them, absolutely.

I think that's the key. We've got to value this right. If we're going from 20 days to 3.5, we need to share on the value split there.

Your next question comes from the line of Jim Crandell with Barclays Capital.

Chad, would you expect to -- in North America with your pressure pumping business, would you expect to adopt a broad-based strategy of trying to package your pressure pumping together with your drilling-related product lines?

Yes, I think it depends on the customer, Jim. As you know, customers come in all shapes and sizes. Some are ready to bundle the entire package for fairly long-term contracts. We talked last quarter about Hess up in the Bakken with a five-year contract, we're doing 80% of the drilling bits, et cetera. And I think we have about 1/3 of the pressure pumping. So there are customers there that are looking for that, and we have others that continue to want to do callout-type basis. We are tying more and more, when we can, with tied to the pressure pumping because it's in such demand right now. But as I said in the comments, some of this equipment has to come off. In particular, the contract of working with the customer before we can then put it together with services and get it out and promote it. But as long as this market's the way it is right now, yes, we will be looking to package more into a bundle.

And do you think the whole nature of the North American business is changing in this respect to where in the future, particularly with the popularity of horizontal drilling in the shelves that more and more of the business will be packaged, and people that have a broad product line, such as yourselves, will have a key advantage in servicing the market?

I hope so. That's why we've been buying all these companies from the reservoir side to the pressure pumping. But yes, I think it will. I think we're applying more technology to the U.S. today than we have in the past. And as a result of that, just like we were talking about the MST tool and other things, this is becoming more of a full scope relationship, especially with the independents and the smaller groups. Looking at the reservoir or looking at the mechanics, rock mechanics, geomechanics, optimizing the drilling performance, coming up with the best completion technology, I think it's becoming more and more of a technical package.

And as a follow-up to that, Chad, in the U.S. pressure pumping market, would you be willing to lock in today's prices for term contracts of a year or more for some of your equipment?

It depends on -- I mean, again, pricing is all over the map, Jim. But we would take some long-term contracts. In fact, there are take-or-pay contracts out there right now. We're participating in some of those, as I know a couple of our competitors are. But I think you just have to look at each one individually and see what else is on the contract, what's pull through, et cetera.

And your frac fleets that are coming on in North America in 2011, are those contracted currently?

Yes. They're not contracted but they are, I mean, we're committed. We've got a backlog of 180 days. But they're not contracted at a set price. Some of those were holding almost for the spec market, you can call it.

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

I just wanted to make sure that I heard some of the earlier commentary correctly. When there's a reference to, I think, a mid-teens kind of margin, were you guys referencing your International business as a whole? Or was that specific to a region?

No, that's as a whole.

And then in terms of the Latin American margin sitting at 2%, 3% for the last few quarters, where do you think Latin America can get to as you get into 2011, on an average basis, or in any given quarter?

Kirk, this is Martin. Our expectations are double-digit exit next year in Latin America.

And that's based on business you currently have in hand or bidding plus the synergies that you referenced?

All of that, plus stabilization in some of them weak markets in terms of the spending and pricing and the overhead cost structures.

And then you talked about pricing improvement across a number of different legacy product lines for Baker Hughes, starting to flow through in late third quarter. In terms of highest magnitude to least magnitude, can you give us some general idea of what product lines we're seeing the best pricing from a legacy standpoint? And then those that are seeing the least?

Kirk, this is Martin again. Again, we're speaking in North America because we haven't seen enough pricing traction internationally. But certainly, it's the typical ones. We're seeing the drilling systems, the lead, of course, is pressure pumping followed by the drilling systems. We have some price improvement occurring on the production side of the business, which would be led by ESPs. And then your product lines which let's just say have more capacity out there, or slightly lower barriers to entry, which would be your case for wireline, and your Drilling Fluids, I'd say it's minimal.

And then just on Chad's comment about the headwind, potentially in the second half of next year from the pressure pumping capacity. What magnitude of pressure pumping capacity do you think is coming into the market from an industry standpoint? And then when you talk about the headwinds, are you talking about pricing pressures, or pricing plateauing? How do you plan and how are you thinking about that at this point in time?

Well, we see there's some more -- depending on who you talk to, 6 million to 6.5 million horsepower up there today, going to 8 million to 8.5 million by end of next year. Those are street numbers but it's not taking into consideration attrition. And right now, we're burning through, the industry is burning through probably 15% a year. So there's over 1 million net horsepower being added here in the next few quarters. Now, again, right now, there's a big backlog. I don't know how strong we'd be facing the second half. We're just going to be watching it going into the first half, and that will determine if we're going to continue to add equipment through next year. I think there's just a lot of variables out there right now. We're watching it, and I think probably, if it slows down a little bit, you'll see some consolidation in the business like we've seen in the past.

Your next question comes from the line of Scott Gruber with Bernstein.

It's clear that you've been more cautious on bidding for the IPM projects in Iraq given the aggressive pricing by peers. Yet at the same time, a pillar of your geomarket reorganization is to capture greater international market share. So I was just hoping to gain some color on the markets or the regions, if you don't want to get too specific, what are you doing to capture market share in the next 12 to 24 months? And the strategy to do so, given the imperative to improve margins as well?

Scott, this is Martin. Let me start with the one you bring up Iraq. If we thought that the market was kind of better defined in terms of what the scope was going to be, what the risk profile is going to be. But I think as you've heard from a couple of our peers, the bidding activity there is very high and there's a lot of work to be done. And this is both from the national oil company, as well as the foreign participants. Let me put it this way, we've participated in every IPM bid, to use that term. We've obviously submitted prices but we've been on the sidelines in terms of getting on the field when the pricing environment is so unattractive. Again, given the fact that, if you see what happened in Mexico, if you see what's happened in some of these other high-profile IPM bids, the opportunity to make a profit is very limited. So I think the industry, our side of the industry, needs to rethink the way it approaches it. That aside, you're right, the reason that we reorganized into the geomarket organization was to grow the top line at faster rates that what we were experiencing before. And as I said in my comments, that's happening. But the best way to further grow those margins is to continue to grow that top line. We're taking actions that we can most -- near-term control in terms of the cost, in getting those down and particularly, in the overhead functions where we experienced some redundancy. Now in terms of trying to get other business, as I said in the comments, there's an incredible response by the customer community, which I think is being rewarded already with the work we're getting. We see the BJ organization stimulating even further, working together. And I can tell you that whether it's Vietnam, whether it's Australia, whether it's the big award we just got in the Philippines, whether it's bringing BJ more solidly into our business in Norway, we're seeing a lot of nice projects come our way. But the final point I'll make here, Scott, is that unlike North America which is a transactional market, we reorganized 18 months. Officially, we had all of our people in place, probably about a year ago. And the international market is not transactional, there's contracts there that are years in the making. And by that, I mean it takes months for the tender to come out, it takes months for the tender to be awarded, it takes months sometimes to mobilize. And it can take months for the customer to actually start spending. So you put that on top of contracts that already ran three to five years. It's not surprising that it takes a while to rebuild the revenue. But in terms of the mechanics, the way we're executing out there, I'm very happy with the job the guys are doing in terms of building their share.

Now would Russia be in the top three or four countries, or regions, just given it's size in terms of markets you identified where you have upside opportunity, or your target?

In Russia? Absolutely, primarily in the Drilling Systems sides. And on the pressure pumping, we're pretty much that represented yet, but we're looking at some opportunities there in terms of how best to address the world's second-largest pressure pumping market.

Now do you think you need rigs, or a rig partner to more effectively compete on the drilling technology side in Russia?

It's always been part of our strategy there in terms of our assessment. But yes, that's a big component. But Scott, the rig need kind of comes and goes, and depending on what's going on in the marketplace. Sometimes you have short rigs and sometimes you can find it right around any corner. So we look at that and if we think that it's the right way to go, then there's some opportunities out there for us to buckle up for somebody.

Your next question is from the line of David Anderson with JPMorgan.

If I'm not mistaken, compared to your peers, you have a much larger portion of your International business that comes from the offshore markets. Just wondering if you have yet to see the impact in offshore services from Macondo. In other words, are you spending more time on the rigs already with new procedures and safety steps, or something like that? Or does it really take a little bit longer to work into the system?

No, I don't think that Macondo, outside of the Gulf of Mexico, has had a huge effect on the offshore deepwater market. Now several clients, several governments for probably a period of a month or two, did take a look and assessed their performance, safety performance, that type of thing, David. But it hasn't really set us back anywhere. We are seeing a lot more requests from clients asking about our training programs, our certification of employees, a little bit more regarding on some of the technology or where we may be running. But I think for the most part, Brazil, Norway, other places, there was a little bit of effect from Macondo, but not much.

And when we look at Eastern Hemisphere for next year and take into account the margin guidance that you gave, kind of mid-teens, some of your competitors are suggesting that Eastern Hemisphere margins will take a lot longer to kind of build up. You seem to be kind of feeling that things are going to move up pretty quickly. What are kind of the two to three components in there that get you to your numbers? My understanding is a lot of these contracts are priced two or three years ago. It's kind of taken a while to work into the system. Can you talk it about from a contract standpoint, from internally, what Baker Hughes is doing? And also from the offshore side, kind of how those three components kind of work into your margin progression?

Well, I think you got to remember we fell a lot further than the competition, so that will allow us to rebound back up a little bit. This isn't totally just a cost structure problem. It's also a tendering issue. Yes, we put our team together 18 months ago and sent them out there. And one of the reasons why was to gain our revenue growth back, which we've done. Now you have to question, are some of those contracts a little aggressive? Yes, probably. And some of them, as they wind off, we will replace them with better margin contracts. That, plus the fact that, as Martin went through, we've made some consolidation and tweaking, if you call it that, for the geomarket structure. This is normal. We did it years ago when I was with another company. And I know one of our rig competitors did the same thing when they reorganized and had to do it a couple of times to get it right. So I think you'll start seeing it in Q4. We have taken some cost out of the system and moving down the path of being able to do that.

I guess the only thing I'd add on there is, David, is the supply chain impacts, as well as the BJ synergies. And on these BJ synergies, not just the costs, but also the revenue opportunities jointly. And again, the Philippines is a tremendous example of that. So you put them all together, we're comfortable with the guidance that Chad mentioned in terms of International.

But it sounds like a big chunk of that's going to happen internally, if I just heard you correctly.

That's correct.

I think a lot of it will happen internally.

Your next question comes from the line of Geoff Kieburtz with Weeden. Geoff Kieburtz - Weeden & Co. Research: Pressure pumping capacity, you mentioned that you've ramped up your expansion of the pressure pumping fleet, but you will modulate that depending on market conditions. What's your lead time now? I mean, how far ahead do you have to make decisions in terms of order date to actually putting equipment in the field?

Well, it's just mainly, Geoff, the big components. It's the power end, the fluid end and the engine, the chassis, the tractor, those type things. You can get those three, four months out. The bigger lead items, you're kind of looking for more like six months. Like I've mentioned, BJ had backed up considerably on the building of equipment during the negotiations and other things, rightly so. So we had to kind of rebuild that supply chain link beginning earlier this year. But we're looked at as a major player in this area and so the major suppliers in those points know that Baker Hughes is going to be in this business for a long time, so they jump through hoops to make sure that we get our equipment. I'd say you got to be looking at around six months. Now if we start to see some things softening or whatever as we go into 2011, doesn't mean that we still won't continue to build out some fluid ends, power ends, engines. Those things can go on a shelf and replace existing equipment or problems as we go through these equipment. So we have some flexibility there. Geoff Kieburtz - Weeden & Co. Research: And the other question was simply, do you expect to take any charges in Mexico?

We've taken everything that -- we take it as we go through it. So if we have the ramp up cost like in Iraq or others, those hit the quarter that we're involved in that quarter. So no, we don't have anything left in it.

Your next question is from the line of Robin Shoemaker with Citi.

I just wanted to return to the International for a minute. A couple of years ago, the margins were hit a bit by the startup costs in some key international markets. Now here more recently, it seems to be reorganization type of cost, geomarket framework and so forth. And I take that your guidance here is that, the 15% level could be achieved, principally without help from the market. But if the market does rebound more strongly than expected, how are you positioned relative, internationally, relative to the infrastructure that you put in place a few years ago to capture that opportunity? Or was part of that startup process left somewhat unfinished?

No, I guess I was confused when you say start-up because I'm usually thinking of actually gearing up to handle a contract. We're putting equipment in there, there's that startup cost but there's also just the infrastructure buildout cost, the facilities etc., which we know are going to be there for the next 30 years. One thing, Robin, I want to clarify, that 15% exit rate that we talked about isn't just going to come just all internally. We are expecting that we will see some improvement in the International activity. We said that it would be modest in growing. But we do expect some of that to benefit the margin side as well and, of course, we also feel from the steps that we're taking on the cost side and organization side, that it will contribute quite a bit itself. I think we're pretty well-positioned. If 2011 is a surprise and the second half comes on strong, we have spent a lot of money over these last five years, both in the solid facility infrastructure side, bricks and mortars, you might say, but also on the human capital side. We have a much stronger International management team based in these key markets, again, much closer to the customer, which I think is one of the reasons why we're seeing some success on the revenue side now. So we'll be able to respond. We're in much, much stronger position today than we were a few years ago to handle International growth. And that's why we did all this, that's what we're counting on.

My follow-up is on the Gulf of Mexico. It seems to be your P&L a little harder than some others, to the extent that this return of drilling drags out and we don't get back to pre-Macondo levels of drilling any time in the next year or perhaps after. What kind of redeployment or perhaps downsizing for the Gulf of Mexico is in your plan? And what are you waiting to see before you kind of trigger that?

Finish the elections. We have about 350 people that, right now, out of the Gulf group that are based in temporary assignments around the world. We wanted to get -- these are some of our major competitors. These are people that have 20 years of experience and can go anywhere on the world to drill or run a bid or whatever. We don't want to lose those people. So we will watch this. We're talking a lot to our customers right now, the majors as well as the larger independents, trying to get a feel for when they think they'll get back to work. Right now, we've got quite a bit of activity lined up if they can go back and drill. We think we're in a pretty darn good position to do well in the Gulf once the activity returns. Now that being said, by the end of this quarter, if we don't see a seasonal return or some positive signs then obviously, we're going to have to take the next step in terms of our cost structure in the Gulf and do something about it. But as Martin said, from a vessel side, you look at it, vessel business is doing fairly well even in the downturn because of reworks and some laterals and things like that on the shelf. And it's the best backlog we've seen in that area. So we think there's enough optimism or enough lift right now that is going to strengthen a little bit, starting in Q1, that we're going to hold on a little longer where we have to do anything.

Today's final question will come from the line of Marshall Adkins with Raymond James. J. Adkins - Raymond James & Associates: Just wanted to clarify the mid-teens margins for International, you guys have done a great job explaining how you're going to get there and whatnot. But that's an exit rate for next year, it's not an average, is that right?

That's correct. J. Adkins - Raymond James & Associates: We start plugging in an average of mid-teens and your numbers go up big. Coming back to the pressure pumping side, you did talk about the industry horsepower. Can you help me understand how much horsepower you've added this year? And I know it's early in the budgeting, how much you think you're going to add next year, and kind of what percent of your CapEx that is going to be?

Well, I don't want to tell you how much we've added because I'd rather let somebody else try to guess and put those numbers out there. I will tell you we are adding a frac fleet every six weeks and have been for the last little while and for the next little while. So that gives you some upside in terms of what we have coming. Now that being said, there's a few factors of why we're adding this much horsepower. One, as I mentioned earlier, the attrition rate is very high for the industry, about twice of what it used to run years ago. And the second area is again, we can look at some equipment, every service company ages their equipment, looks at the life of the equipment and so on. And there's a 10-, 11-, 12-year-old equipment out there in the BJ ranks that we want to be able to replace in time anyway. So we're adding this horsepower now and if we do see it slow down then we'll get rid of some of the older stuff. I hope that answers your question, Marshall. J. Adkins - Raymond James & Associates: How about percent of CapEx? Can you help us with that?

Percent of horsepower CapEx versus our total CapEx? J. Adkins - Raymond James & Associates: Yes. You gave us guidance on total CapEx, but how much of that is BJ chewing up?

You got our numbers from the beginning of the year. We talked about somewhere around $1 billion to $1.1 billion of Baker Hughes legacy CapEx, and Peter said we're going to be around $1.7 billion for the year. J. Adkins - Raymond James & Associates: Last part of this, 15% attrition rate for the industry, are you guys in line with that 15%?

Yes, I mean we go by some of the things we hear from our customers. Customers tell us that our equipment and one of our other competitors, major competitor's equipment seem to be holding up a little better in areas like the Haynesville and others. And I think that's helped us pick up share there. But I think we're at the leading edge of not tearing up as much equipment as some of the people out there.

All right, thanks, Marshall. And thank you Chad, Martin and Peter. I want to thank everyone, all of our participants this morning, for your time and your very thoughtful questions. Following the conclusion of today's call, both Alexey and I will be available to answer any of your additional questions. So once again, thank you for your participation. Dennis?