Good morning. My name is Thia, and I will be the conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Fourth 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, Thia. Good morning, everyone. Welcome to the Baker Hughes Fourth 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 Officer; 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. Finally, I would caution you this morning that any company outlooks discussed are subject to various risk factors. We'll try to highlight these factors as we make these forward-looking statements. However, the format of the call does prevent a thorough discussion of these risk factors. For a full discussion of these 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 $335 million or $0.77 per share. There are some adjustments that should be made to better compare our results to first call estimates. First, we have incurred $56 million in acquisition-related costs this quarter. Net of taxes is $37 million or about $0.08 per share. Second, we also had a gain on investment of $6 million or $0.01 a share to another direction. So adjusting to these factors, the EPS that is more comparable to first call estimates was $0.84 per share. Revenue was $4.4 billion, up 82% or up almost $2 billion compared to a year ago and up 8% or $345 million sequentially. And EBITDA per share was $2.18, up $1.07 or 96% compared to a year ago, and up $0.54 or 33% from last quarter. To help in your understanding of the moving pieces, I'll bridge Q4 '09 EPS to Q4 '10 EPS. GAAP EPS for Q4 '09 was $0.27 per share. Subtract a $0.01 for a gain on investment in the year-ago quarter, subtract $0.08 for the impact of the higher share count a and higher effective tax rate, subtract $0.03 for higher net interest costs, subtract $0.05 for the impact of the incremental amortization costs associated with the acquisition and add $0.02 for lower corporate expenses. Operations added $0.72 per share. That brings us to $0.84 EPS per share. Last, subtract $0.08 per share for the impact of the acquisition-related cost, and add the $0.01 gained on investment this quarter to get to the GAAP number of $0.77 per share. Bridging the sequential quarters, GAAP EPS for Q3 2010 was $0.59 per share. Subtract the impact of the higher relative tax rate of $0.02 per share, subtract $0.03 per share…

Thanks, Peter, and good morning. Let me start with North America which had an outstanding quarter across all the geo markets. The story for North America land centers on the unconventional reservoirs and the use of horizontal drilling, advanced completions and pressure pumping to access the reserves. Baker Hughes is a leader in these products and services. Beginning last September, when BJ's U.S. operations were formally merged with ours, we moved with agility to leverage the strengths of the legacy Baker Hughes product lines with the newly acquired capabilities of BJ Services. For example, in the Bakken shale, the newly combined organization worked together to win an award. From a U.S.-independent to drilling-complete multiple wells, they're expected to have 30 fracs stages each, highlighting the continuing increase in service intensity we are experiencing. We're providing the drilling services, drill bits, fluids, wire line, completions, cementing and pressure pumping services. In the Pinedale anticline in Wyoming, we were awarded logging, stimulation, completions, perforating and pressure pumping for wells with 11 frac stages each. Further south in the Eagle Ford, we were awarded stimulation services, coil tubing and wire line services on wells being drilled by an independent that are expected to have 25 frac stages each. And in Canada, work in the primarily oil focused unconventional shale place also contributed to our North America performance. In addition to the unconventional shales, we are also an active player in the oil sands, where we provide drilling services, completion, equipment, and of course, chemicals and artificial lift. Recently, our new ESPs have set performance records for continuous operations. In the Alberta oil sands, our extreme temperature ESP systems set a record run life in a SAGD application of more than 800 days of continuous operation in one of the harshest ESP environments imaginable.…

All right. Thank you, Martin. Good morning, everyone. It was a very good quarter for Baker Hughes. North America margins increased almost 500 basis points, and we had good revenue growth as the company responded to its strong unconventional shale market. International margins improved 375 basis points on strong sequential revenue growth, and clearly benefited from the emphasis on cost control and our focus on improving international margins. Reflecting on this quarter and looking forward, first, in North America on land. Activity in the unconventional shales remain strong. Horizontal drilling which now accounts for 57% of the U.S. rig count, accounted for a little less than a third of the rig count at the peak of the last cycle only 28 months ago. In absolute numbers, it is 52% higher today than it was in September 2008. In recent weeks, horizontal drilling has held up well. We are seeing the shift from dry gas to wetter gas and to crude oil plays. As a result, gas-directed horizontal drilling fell 4%, and oil-directed horizontal drilling increased 30%. All in all, since the end of the third quarter, horizontal drilling has increased overall 6%. And importantly, the service intensity has also continued to increase. We're seeing both longer horizontals and tighter spacing between frac stages resulting in more stages and therefore, higher demand for hydraulic fracturing. So far, the industry has been unable to keep up. Depending on the basin, pressure pumping capacity remains tight with backlogs stable at anywhere from 90 to 180 days and therefore, supporting higher prices. Completions in directional drilling equipment and services are also in short supply and are realizing price increasing as well. The supply chain for new equipment is stretched. In fact, we question the ability of the industry to grow pressure pumping capacity faster…

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

Yes, sir. The first question will come from Bill Herbert with Simmons & Company.

With regard to your international outlook. Martin, if I heard you correctly, you expected that in Q1, we would see a $70 million down tick from the year-end product sales that we saw in the fourth quarter?

Correct.

So I guess the question is for international Q1, x the impact of product sales, is international in Q1 higher or lower relative to Q4? And what I'm trying to discern is impact of seasonality versus project startups.

I don't think we really want to go into that amount of detail as compared to the international specific in Q1. But, Bill, if you go back over our history, the effects of, not only the product sales but the seasonal effects in and parts of the U.K. particularly and Russia, put pressure on international. But that all said, as you know we have some other underlying initiatives underway to try to alleviate those kind of market effects, whether it's further cost refinement, whether it's the supply chain kicking in, as well as trying to extract some more synergy out of the BJ organization in the eastern hemisphere particularly. Whatever effects we get from the market, I think we still have some tools in our toolbox to mitigate it.

So historically, right, if you go back to 2006 when you guys started reporting or you got the geo market reporting format, your revenues are down historically 5% quarter-on-quarter and then you x out '09 and 2008 which were extreme years, you're down anywhere from, call it 1% to 7% quarter-on-quarter. So it sounds like the seasonality is likely going to outweigh project startups or we'll assume you're down in addition to the product sales. And then, Martin, with regard to the evolution of the, if you will, the roadmap for international margin improvements, supply chain initiatives, efficiencies, BJ consolidation savings and what have you, of the almost doubling in operating income in the fourth quarter internationally, how much was due to that evolution or with regard to the several different initiatives for international margin improvement?

You could parcel it up in a variety of ways. The things that we have under our control and some of them have to, let's say, be a little bit more market driven and some of them just take a little bit longer to materialize. And you attack what you can when you can. And I think it's fair to say that the internal cost adjustments were the predominant driver for the improvement in this particular case, in the near term of this journey that we're on. And we're probably 1/2 to 3/4 let's say through that in terms of the overhead particularly. And the supply chain, which is on the other side, the other book end to that, it kind of kicks in, in the second half of the year as we work through our inventory. Does that make sense?

Yes it does.

And then in the middle of that, there's an activity mix, share attack, if you will, that plays in as well. So the front end was loaded with internal costs for sure.

And Chad, finally for me, with regard to your outlook for U.S., it looks like you guys are prophesying, if you will, a U.S. rig count which is flat to up from current levels for 2011. And based on that and currently based upon your overall commentary with regard to service intensity, continued pricing momentum and the difficulty in putting new horsepower to work, it doesn't sound like you expect your U.S. land margins to rollover anytime this year. Is that a fair comment?

Yes, it's a fair comment, Bill. Perhaps towards the end of the year, we may see some as capacity comes in and some softness, but we continuously shift towards these oily wetter plays, and we're seeing, I mean, very little back off in terms of longer horizontals, longer extension, clients are even pushing out 8,000, 10,000 feet now. That's just involving more fracs, and when you start thinking about it, we're finally starting to see technology hit the U.S. which we've seen overseas for years and years. I mean we've been drilling 35,000 foot-extended reach wells overseas. And we just recently, completed a six and eight, 36,000 feet in Saudi, so why won't we continue to see that in the shale plays in the U.S.?

The next question will come from Ole Slorer from Morgan Stanley.

Back to the BJ Services integration, glad to see that certainly the numbers that you are putting up or suggest that this integration is now going very well. Can you give us a little bit more detail over the next couple of quarters when this comes to -- I know that closing the gap on margin to your two key competitors in North America is an objective, and you have come a long way here but there's still a little bit more to go. So how much and when it comes to closing the margin gap to your two key competitors, how much of it is from fine tuning the two organizations, cross selling or leverage on some of your investments that relate to add capacities? So can you give us a little bit of a roadmap and the timing in order for you to play out?

Yes. Ole, I think our gap's fairly tight. And if you look at North America with one of our major competitors, I think we're about the same or a little bit ahead of them and slightly 100 basis points behind the other one. We've really only been able to start to integrate the North America pressure pumping with directional drilling completions, et cetera, starting in September when we actually took over. So Q1 was our first real quarter of seeing some benefit in that, and I think our margins went up in Q4, margins went up 400, 500 basis points. So I think we definitely started to see the improvement there. Q4 of North America, actually we saw a lot of the improvement coming from BHI legacy as we saw price improvement coming from directional drilling, fluids, bits, et cetera. Internationally I think is where our next big potential way will come on revenue synergies between traditional Baker Hughes and BJ. So I think we'll start seeing that in Q2, Q3 as we start seeing those revenue synergies come through.

I noticed that the North Sea is traditionally one of your highest-margin businesses as well as a strong margin or strong area for BJs like it's a business as well. Could you give a little bit of a roadmap? It's your weakest margin, at least the Europe, CIS, West Africa, it's your weakest margin, what's your opportunity to take that back towards historic highs and what's the timeline given the very ambitious CapEx predictions for both the U.K. and Norway for 2011?

Well, don't let them irk the Europe, Africa Russian overall margins mask or hide the success we've had in Europe. I think we don't break those out but clearly, Europe is very strong for us. Continues to be strong and we see it strong through 2011. Now BJ, historically, is not all that strong in the U.K. or in Norway. We think this is one of our big opportunities as we are able to bring them in, in other areas but they're not big in the U.K. or Norway. This is one of the things that we were excited about when we bought them. Because if you look at their offshore sea mining capabilities in the rest of the world, it doesn't repeat in those two markets. And that of course, that obviously, takes time as these sea mining units are buried in rigs and so on. But we think that's a big opportunity for us, probably not before the second half of the year but we are seeing pull through already on coil tubing and pipeline, machine and other things in Europe. Now Continental Europe, BJ is much stronger in terms of some of the frac-ing and other things that we see on continental land Europe and eastern Europe.

And so on your international margins, are you still of the view that you have your two biggest competitors as a realistic target for chasing them on margins and revenue growth?

Yes, that hasn't changed.

The next question will come from Daniel Boyd with Goldman Sachs.

Follow up on your expectation for margins in Africa to improve. Can you just comment on what is going to drive that? Is that a pickup in activity that you see happening or is it additional cost cutting?

Well, I think it's a combination. There's a little bit of additional cost cutting that takes place. We did quite a bit in Q4, but we haven't finished it yet which will happen in Q1. We also see an improvement coming back in North Africa. That's been pretty depressed for everybody this last year. So we see that getting a little bit stronger. We've got work to do in Angola which is an area where we've invested heavily, and has been a challenge for us. Nigeria is kind of a moderate quarter, I think, for everybody, a weaker quarter but we see Nigeria, we're well positioned in Nigeria. We think Nigeria will be a contributor for us in 2011. And in sub-Sahara Africa, we've had some good wins and good successes there in Ghana, Gabon, Uganda, picked up some several different contracts there. So I think it's just a matter of getting Africa sized to what we need and at the same time, continue to win some contracts in 2011. And getting that from a point where it's hurting us or deluding us versus contributing. So I guess that's the best way to summarize it.

Are all those positives enough to offset the seasonality you might see in the first quarter to maintain margins in that region or I guess, the overall geo markets?

No. There's not a lot of seasonality for West Africa or North Africa. It's not a big area where we sell huge amounts of products or sales. I think Q1 will be better for Africa than what it was in Q4.

I meant more of the seasonality that you see in Europe and Russia.

No.

And then just on the pretty ambitious CapEx program that you've thrown out there, I know part of the story with Baker is now harvesting some of the fixed-asset investments that you've made over the past few years. And then going forward to see such a big increase out of you. Can help you understand where that's going, International versus North America? But also is it in support of contracts you've already won or in anticipation of contracts to come?

Well, I think first off, keep in mind whereas last year, we didn't own a pressure pumping company. This year we do, and it is much more capital intensive. If you look at $2.3 billion to $2.7 billion that we're saying our range compared to our revenue, it's not that far off from one of our major competitors, what their revenue is, just a major pressure pumper, who just announced $3 billion. So I think a significant portion of that $2.3 billion to $2.7 billion does sit with pressure pumping and horsepower. We are playing a little bit a catch up in that area because BJ really cut back in 2008 and early 2009, on CapEx. I think they are $200 million or less in the entire year of '08. We did kick that up to some degree in 2010, and we see just an ongoing need for additional horsepower. We're no different than, I think, couple of our major competitors, we're pretty tight on horsepower sold out in North America.

Have you increased the cadence on pressure pumping deliverability? I think you're doing one crew every six weeks.

No. It's probably about what -- we're staying in that pace, one frac, 30,000, to 40,000 horsepower every six weeks.

The supply chain is still stretched. I mean that hasn't changed. So that's, I think, when Chad mentioned earlier in the comments, we've been unable to keep up. Part of that is not just our own efforts, but it's our supply chain efforts on getting the capacity through the system.

The next question will come from Kurt Hallead with RBC Capital Markets.

Chad, when you look out at the opportunity set for 2011 and specifically focus on the international marketplace, how would you risk assess the outlook? And do you think that there's more upside to that 8% growth number on the rig count or you think there could be some -- if push came to shove more modest downside on project delays or otherwise?

Well, Kurt, I'm pretty bullish on the second half of the year. I think the second half of the year, with what we're seeing right now, the optimism of the client, the price of oil holding in, as well as it is held, a lot of projects have already been delayed. Quite a few customers talking about improving on their exploration programs, they're starting up, which they can fairly quickly. We've had some nice contract wins which will start up towards the second half of the year. So I would risk it to say I think the second half, especially Q4 could surprise us and start showing some strong growth and momentum. We talked about the price improvement, we don't really see it happening and if it happens until end of the year and that really price moves when activity really starts to move. And that's when things tighten up.

And in that context of pricing and pricing increments going on in 2012, what geo markets do you think might be best positioned for improved pricing? And if you were the kind of handicap from a product line standpoint without magnitudes, of course, but if you -- handicap the product lines, which ones do you think have the most pricing power as you get out into latter '11 and into 2012?

Well, I read the transcripts and one of you guys asked one of our major competitors that question, and they refused to answer it because it would tell the competition. So since he didn't answer it, I don't think I'll answer it either.

The next question will come from Joe Hill with Tudor, Pickering, Holt. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Chad, when I look at your comment that you question the ability of the industry to grow frac capacity faster than demand in most foreseeable scenarios, and you've got, I think what looks like 12% or 13% U.S. rig count growth for 2011, there's assumption in your comment that there's a certain amount of stage gain year-on-year as we do more intense frac-ing. What are you figuring that is?

Where do I figure the staging is? Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes. The number of stages per well.

Well, it varies depending on the basin, but we're seeing -- Mark referred a couple of big contracts with 30. 35 is not uncommon. Some basins, there is 10 to 11. So I think we're probably at 20 to 25 stage-type fracs today. And again, this comes down to the horizontal link, the drilling. I think the average -- you could probably say horizontal drilling today extended reach is 6,000 feet on average. Clients are kicking that up to 10,000 feet. That's why they increase in stages. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: So something like 30-plus percent growth in stages year-on-year?

I see where you're coming from. I don't know the answer to that. I'd have to get back to you on that. That's a good question. It's definitely increasing. I think my comment was more back to the fact -- I think if you add everybody up, and depending on who you look at, we're talking anywhere from 4 million to 6 million additional horsepower people talking about by 2011. And the supply chain, external supply chain to us and to many others, I just don't see a way in the world that, that could possibly be delivered because we're waiting on some things now. So I don't think that's going to happen. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Just kind of a little bit more of a detail question. The Ultra-Slim Equalizer, and this is probably for Martin, is going to allow you guys to address how many wells in the Middle East that you couldn't address before?

Not very many because... Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: So very few, less than 5-inch borehole.

We're the one drilling these coils tubing -- the majority, I think, going forward given the bottom-hole assembly that you're aware of. But you know the Equalizer made its name in the Middle East several years ago. It's just the natural evolution that now that we're drilling these type of let's call them drain holes, they're going to want the same technology, and we're the ones to run it. Joe, I want to follow up though on a comment that Chad made there. This is a tremendous business to be in right now when you think about unconventional well bore construction. The INTEQ guys, as well as their industry competitors, get up every morning trying to drill longer laterals, right? And then the BLT guys and the completions guys, again, as well as the major competitors, get up every morning trying to run longer and longer completions with tighter and tighter frac stage spacing. So back to Chad's comment about what's been done in the Middle East and some of these other places, we just don't see an end. There's probably some diminishing returns eventually in terms of length and number of stages but depending on the reservoir, we don't know where the end of this is, but we do know that we're a big participant in driving it all the way to wherever that end is. And we just don't see any stoppage at this point. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Then finally, Chad, you said something that I thought was pretty interesting. You said that directioal was actually pulling through frac in some instances. And I was just wondering if you could give us a little more color around the improvement in the directional market relative to pressure pumping?

I think just what Martin said, the longer, more complicated horizontals and laterals are requiring better control, better geo steering and much better completions. And of course, if you're drilling through the sweet spots and being able to run the proper completion and getting in the perf fact or whatever system that you want as a completion in the whole, then that, in the sense, the clients come in to us, they're saying, "Well, this is what we want, " then, "We can turn around, it's okay. We would like the pressure pumping well." So it's just that we've just seen -- in the fourth quarter, we saw a strong demand for our directional drilling and completion services. And as a result of that, we were able to pull through BJ on some jobs. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Well, do you think in 2012, we could see pressure pumping hand the leadership baton over to directional?

I think as time goes on, with the complicated completions and drilling and everything else, you're going to be looking at a package-type program which will be much more technical in nature, much longer in reach, much more reservoir in the area of reservoir understanding and prior to drilling these wells. And I think that's the direction the clients are going to be looking to go.

The next question will come from Scott Gruber with Bernstein.

Well, pumping has received the majority of attention. Artificial lift sales have also been quite robust in North America. The question on the origin of the demand growth, has it all been from the traditional basins or are we actually seeing material growth out of the emerging shale plays for lift as well?

I don't know that much coming out of some of the shale plays yet. I'll let Martin answer that. I think North America, one of the big areas where we're seeing artificial lift growth and help, as Martin referred to it in his comments in Canada. Some of the SAGD and other, even in California, but these extreme high-temperature, high-pressure ESPs, it's a very, very technically challenging market 400-plus to 500 degree bottom-hole temperature. So when you can start getting tools down there then get an 800-day run light, and this is what ESPs are all about, not having to pull these things. Martin, do you know anything about the shale play in ESPs?

It's a bit of a -- there's definitely a de-watering element in this side, but there's a -- what do they call it, kind of a rediscovery of the Permian because of where oil prices are, and that's a big, big, big market for our ESPs. And then don't forget the Gulf either. Aside what's happening on the permitting/drilling side as our customer want to get the production back up, we're seeing quite a bit of artificial lift there. So it's really a liquids driven, and there is an element of traditional oil as well as, let's just say, water management on some of the gas side of the business.

And I know you're reluctant to talk price on a product line level. But is pricing in lift approaching the 2008 peak?

I don't think that's pricing on ESPs has never have really been hit that hard through the downturn. And if you look at our -- this is one thing in our production side of the business, chemicals and ESPs, we saw some softening but not anything like what we saw in bits and directional drilling and pressure pumping and everything else during that downturn. So I would have to say it's fairly close to where we were in 2008.

The next question will come from David Anderson with JPMorgan.

I just want to go back on the CapEx question. You talked in the past about realigning your manufacturing operations to get closer to the customer. And just kind of curious on where do you stand right now on that? And is part of this CapEx budget going towards building out more manufacturing in Eastern Hemisphere? Halliburton was talking about that a bit yesterday. I was just wondering if you're planning to do the same.

Yes, we are, and part of that is international manufacturing roofline.

So if we think about that kind of realignment manufacturing, can you just kind of give us a sense as to how far along you are in that process? Are you where you want to be now? Are you a couple of years away?

We're on our schedule. We're happy with where we are, but I'm not so sure if you ever really end in it. Though I expect that it's a pretty sizable portion of new, let's say, capacity will be built internationally relative to where we closed this year, and the answer is yes.

Just shifting over to North America. One of the things I'm starting to hear about is our cost inflation. And particularly, sand and propanes. Just wondering if that's a concern that could impact your margins a few quarters down the road? Presumably, you can increase pricing to match inflation, but I guess do you have enough sand kind of lined up to meet your existing and new capacity going forward?

Well, sand is always, in these times, sand and propanes always become a challenge. Water is a challenge right now. We're able in this market, if we do get that price increase from our suppliers, we're able to pass that on. And if the market should soften and we go down and we go back to our suppliers, they cut back on their pricing to us. So I think right now there is a little bit of inflation taking place, but we're able to handle it.

And with all the talk about the capacity coming on, I know there's concerns about too much capacity is going to crush price. But is it possible that some of this, I guess, supply bottlenecks could support that capacity coming on in your opinion?

Absolutely. I think it's not only just propanes and guars but it's the engines, the fluid ends, the power ends, transmissions, chassis, you start adding 4 million horsepower, that supply-chain becomes tight. And a lot of those suppliers will look to who's been in business a long time, who's going to be in business a long time and they prefer to make sure they're providing those components to those people. So we like the position we're in from that standpoint. Due to volume, we get better pricing from our suppliers, and we also commit to some things. There's enough room out there that if we see a downturn, we're able to go ahead and adjust. And we've got about a six-month window there that we're committed to, and we watch it quarter-by-quarter. So at the end of the first quarter, if we see something changing, we can adjust which will affect Q4.

In Mexico, BJ had a bunch of pressure pumping equipment done in Mexico. Has that all been reallocated to the States?

No, not all of it. There's still capability there.

The next question will come from Robin Shoemaker with Citi.

Just a clarification on the range of CapEx of your guidance. Is that a function of how much pressure pumping capacity you actually add at the high end or low end? Or is that the swing factor?

Yes, that's the swing factors. As I just was mentioning, Robin, $2.3 billion to $2.7 billion, and we will watch that as the quarters unfold. So that would be the swing level. And part of it too is how much can we actually deliver on that, because we're just like I said, everybody else. We've got a significant growth in CapEx and can we deliver all of it to the field.

And so if the market were to significantly slow, how quickly could you put the brakes on this capacity expansion of every six weeks you're adding a new frac spread?

Well, as I said you're looking at about a six-month window in there. So some components maybe it's four months, some components, it's six months. And that's not just for pressure pumping. We see that in the directional drilling, wire line tools, et cetera. So I think your four- to six-month commitment timeframe.

And then finally, in terms of your preference or strategy with regard to putting your pressure pumping capacity under long-term contracts versus maintaining some at more spot rates or giving you the flexibility to push pricing on a short-term basis, do you have any preference in terms of allocation of your capacity in that respect?

Well, we like the flexibility. We like some long term, and we've got a big one in the Bakken that's five years. It ties up 85% of their DD, LWD bits, et cetera. And I think about 35%, 40% of pressure pumping. That's a five-year type contract. We've got quite a few two-, three-, four-, five-month type commitments to clients. We've recently had some discussions with some major or some fairly large independent clients regarding a much longer-term relationship to work on the total package, whether are we going back to in terms of the reservoir, the drilling, the completion, the frac-ing, the overall picture and looking into longer-term relationships. So we like this mix package to be a little flexible.

And when you do experience cost pressures, either labor or materials, freight, whatever, are you able to push those through fairly quickly with whether it's term or a spot rate?

Yes. In the U.S., you can push them through fairly quickly compared to others with international, which is much longer-term contracts.

Thank you. I wanted to thank Chad, Martin, Peter, everyone, all of our participants this morning for your time and your thoughtful questions. Following the conclusion of today's call, both Alexey and I will be available to answer any additional questions you may have. So once again, thank you for your participation. Thia?

Thank you for participating in today's Baker Hughes Incorporated conference call. This call will be available for replay beginning at 1:00 p.m. Eastern, 12:00 p.m. Central time, and will be available through 10:00 p.m. Eastern time on Tuesday, February 8, 2011. The conference ID number for the replay is 35151016. The dial-in number for the replay is 800-642-1687 in the U.S. or (706)645-9291, international. You may now disconnect.