Good day, ladies and gentlemen, and welcome to the Halliburton First Quarter 2012 Earnings Release Conference. [Operator Instructions] As a reminder, today's conference call is being recorded. I would now like to turn the conference over to your host, Kelly Youngblood, Senior Director, Investor Relations. Please begin.

Good morning, and welcome to the Halliburton First Quarter 2012 Conference Call. Today's call is being webcast and a replay will be available on Halliburton's website for 7 days. The press release announcing the first quarter results is available on the Halliburton website. Joining me today are: Dave Lesar, CEO; Mark McCollum, CFO; and Tim Probert, President, Strategy and Corporate Development. I would like to remind our audience that some of today's comments may include forward-looking statements, reflecting Halliburton's view about future events and their potential impact on performance. These matters involve risk and uncertainties that could impact operations and financial results and cause our actual results to materially differ from our forward-looking statements. These risks are discussed in Halliburton's Form 10-K for the year ended December 31, 2011, and recent current reports on Form 8-K. Our comments include non-GAAP financial measures. Reconciliation to the most directly comparable GAAP financial measures is included in the press release announcing the first quarter results which, as I have mentioned, can be found on our website. During the quarter, we recorded a $300 million charge, which amounts to $190 million after tax or $0.20 per diluted share for estimated loss contingencies related to the Macondo well incident. In our discussion today, we will be excluding the impact of this charge on our financial results. As always, we will welcome questions after we complete our prepared remarks. Dave?

Thank you, Kelly, and good morning to everyone. I'm very pleased to report the following results that were achieved in the first quarter. Total revenue of $6.9 billion and operating income of $1.3 billion represents growth over the first quarter of 2011 of 30% and 63%, respectively, which I believe demonstrates how well we have executed against our targeted investment strategies. These are very strong results, especially considering the industry disruptions in North America related to rig movements and the harsh weather we experienced in the Eastern Hemisphere in Q1. Despite these challenges, we achieved record revenue during the first quarter in our North America region. Globally, both our cementing and Baroid product lines achieved record revenues in the first quarter, with cementing also setting a record for operating income. Looking at the North America results for the first quarter. Our revenue grew sequentially by 1% compared to a U.S. rig count decline of 1%. Now while 1% seems small, it's actually the net impact of a significant rig shift that is taking place in the U.S. between natural gas and oil. And operating income was down sequentially by 5%, driven by the inefficiencies associated with equipment relocations, cost inflation and certain pricing pressures in certain basins. Last quarter, we spoke in detail about the disruptions resulting from rig movements between basins. Depressed natural gas prices have accelerated the shift from natural gas to oil plays during the quarter. In the U.S., the natural gas rig count declined 151 rigs or 19% just since the beginning of the year. And that slightly outpaced the oil-directed rig count increase of 125 rigs or 10% over the same period. So while the total rig count only declined 1%, the shift from natural gas to oil was dramatic and disruptive to operations. In…

Thanks, Dave, and good morning, everyone. Our revenue in the first quarter was $6.9 billion, down 3% sequentially from the fourth quarter. Total operating income for the first quarter was $1.3 billion, down 7% sequentially. North America revenue grew 1%, while operating income declined 5% compared with the previous quarter. As Dave mentioned, inefficiencies associated with equipment relocations, continuing cost inflation and pricing pressures in certain basins impacted our margins during the first quarter. We expect disruptions related to rig movements to impact us in the near term. And perhaps with the exception of guar, we anticipate some relief from suppliers in the second half of the year related to high cost of proppants and other materials. Due to these challenges and the negative impact of the seasonal Canadian spring breakup, we expect to see lower revenues and margins dropping by 200 to 250 basis points in the second quarter. We also now anticipate margins could drift toward the low 20 range by the end of 2012. The market is understandably very dynamic right now. These margin expectations depend on, among other things, our success in recovering inflationary cost increases from our customers and how soon the natural gas rig count levels off. We should have a better feel for this after the second quarter. Internationally, revenue and operating income declined compared to the previous quarter, driven by the traditional seasonal reduction of our international business. In the first quarter, we also usually see weather-related weakness in the North Sea and Eurasia, and this year was no different. As we look ahead, we anticipate our Eastern Hemisphere margins will reach the mid- to upper-teens in the second half of 2012 and average in the mid-teens for the full year. Now looking at our first quarter results sequentially by division. Completion…

Thanks, Mark, and good morning, everyone. As Dave outlined earlier on the call, we've been very consistent in our outlook for our international markets, where we continue to expect gradual activity improvement based on meaningful increments in customer spending patterns and corresponding new rig arrivals. Growth drivers for us in the international markets revolve around the execution of our strategy in deepwater, mature assets and unconventionals. In deepwater, we continue to be pleased with our positioning. And globally, the deepwater services market is expected to grow by approximately 20% per year through 2015, with exploration spending growing 4% annually and development growing by 35% annually. And as this shift gets underway, we feel that Halliburton's well positioned to participate in all established and emerging markets. In East Africa, for example, there are now 5 deepwater rigs running compared to just 1 this time last year. And our new basins in Mozambique and Tanzania are now well established as a platform for long-term development there. Establishing a stronger position in deepwater for our wireline and testing services has been a priority for us, both in terms of technology development and market positioning. In addition to wins in East Africa, the logging package fee win for Petrobras in Brazil is a positive indication of our credibility in this market. We also believe, as Dave mentioned, we're well positioned for the deepwater drilling and testing tenders in Brazil. In mature assets, our customers continue to look for assistance in evaluating, planning and executing redevelopment programs. In Mexico, for example, our customer PEMEX took a thoughtful approach to redevelopment in Chicontepec. Our Remolino field lab generated an improved understanding of the subsurface, and combined with new technology applications and joint team work, is delivering outstanding results. The PA-1565 well that Halliburton drilled had an…

Okay, thanks, Tim. Let me just quickly summarize, and then we'll go to questions. We're very proud of the results that we delivered in the first quarter, with double-digit percentage growth in the first quarter of 2012 in all geographies in most product lines. In North America, the impact of inefficiencies from rigs moving from natural gas to oily basins to pricing pressure and cost inflation will impact our profitability in 2012. We plan to mitigate these impacts through continued focus on execution, efficient supply chain management and cost recovery from our customers. We remain very optimistic about our Latin America business and believe recent operational success and contract wins position us well for the future. And we continue to be optimistic about Eastern Hemisphere, where we expect our margins will continue to improve throughout the remainder of 2012. So let's open it up for questions.

[Operator Instructions] Our first question comes from David Anderson of JPMorgan. John David Anderson - JP Morgan Chase & Co, Research Division: Well, I'm sure you get a lot of questions about pressure pumping pricing. So I guess, my angle on this is I'm curious about where spot prices are now relative to the pricing on your existing term contracts. Just wondering, are spot prices now in line with term? And how would you expect those contracts to get repriced? I mean, would it be a material change, is it down 10%? And I guess as follow-up to that, are you starting to see E&Ps sign up any term contracts now? Or is it still too early?

Well, Dave, this is Tim. We're still 80% to 85% long-term contracts. And so our exposure to the spot market is really quite limited. And clearly, there is, as Dave pointed out, a more aggressive stance in those spot markets, but it's one which frankly we're just not exposed to that much.

And let me also -- Dave, this is Mark. I'd also add, it definitely varies by basin in terms of the, we're still signing up term contracts. We have customers in certain of the liquids basins that are only re-signing up for term contracts, they're extending the contracts that they have and they're still continuing to be at fairly good prices. John David Anderson - JP Morgan Chase & Co, Research Division: But are they lower than they were before, I guess, is my question. And how much lower? Is it like a 10%, is it material?

In some of the oil basins, the answer is no, they're not lower. John David Anderson - JP Morgan Chase & Co, Research Division: And I would assume the Eagle Ford is probably the most vulnerable out of all of those?

Yes. I mean, clearly, its proximity to the Haynesville makes it a much more vulnerable basin. John David Anderson - JP Morgan Chase & Co, Research Division: Okay. And as a related question, you were talking about your CapEx, and it looks like you're on track to spend less. But Mark, it sounded like you just kind of reiterated your $3.5 billion to $4 billion number. Just wondering if the North America market doesn't show any signs of tightening, you're saying you think your second half looks a little bit better. But if that doesn't happen, would you expect spending to start -- to cut spending and maybe be below that range? And now you've got Macondo just on the rearview mirror, just wondering what the thoughts are. I mean is there a potential for a buyback here, when you -- considering where your stock is trading now? If you cut CapEx, maybe buy back here at $32 here?

Well, let me take the questions in order. I think with regard to CapEx, I still feel very confident that we're going to spend in that range of $3.5 billion to $4 billion. What I was trying to reiterate, that even though we may slowing down some of the equipment deliveries in North America, there's still quite a bit infrastructure that we're building out related to our facilities, the transloading facilities for sand and other activities here in the U.S., as well as we are winning quite a bit of international tenders that are requiring incremental capital to what we had built into our original plan. And so there is a shift of CapEx fairly immediately for mobilization into some additional international work that we're pretty excited about. So in total, I don't see a big shift and it's difficult for me to see, based on the outlook right now, that we would step down meaningfully from the CapEx number. Now towards your second question. We accrued something on Macondo. It's one of those that based on our evaluation of events that had transpired through the course of the quarter, we felt the need to do that under U.S. GAAP. However, I would say that we're a long way from having Macondo behind us. I mean, right now, we are still in litigation mode. There's still a fairly uncertain calendar as to when events around Macondo will take place. And so until such time as Macondo is dealt with in its entirety, I think it's going to be difficult for us to strategize on what other kind of corporate initiatives we might do with regard to any excess cash that we might have.

Our next question comes from James West of Barclays.

Mark, quick question for you on North American margins. So we've got another decline in the second quarter, 200, 250 basis points. And then you alluded to margins perhaps dropping into the low 20% range, I think, in the second half. Correct me if I'm wrong on that.

Yes. It's sort of the trend toward the end of the year is what I'm alluding to.

Okay. So is that -- would that represent the bottom, given what you see currently in North America? I mean, some of that's just a mismatch between vendors, and some of the pricing declines in pressure pumping. And then is this -- are you backing off earlier statements that you guys have made that normalized margins would be more like in the mid-20s? Or is that still achievable after we kind of shake out 2012?

Well, to the first question that you ask, I think based on what we can see today, yes, that low 20s feels like that, that's a bottom. But again, as I mentioned, there's still a lot of movement out there. It's a very dynamic market, and so we'll continue to try to adjust as we see. I think towards your second question, our comments last quarter about normalizing in the mid-20s, related really to our outlook for the year of 2012. It's difficult at this juncture, given the dramatic decrease in the gas rig count and the current outlook for gas, to say that we would normalize at that point there. I mean, that's – so I am -- we're kind of coming off of that earlier guidance, at least with regard to 2012. I'm not going to try to crystal-ball where we see things going in 2013. But I do think structurally, in our business, when you look long term, through the cycles themselves, that mid-20s range is essentially where our business tends to operate. And we are driving initiatives inside the company to reduce our cost structure in a way that can give us a fighting chance even if the market begins to flatten out toward the end of the year that we can find our way back to those mid-20s range if we execute well against our cost initiatives.

Okay, that's very helpful. And then just one question on the international side of the business. Is there real spare capacity internationally right now? And if not, at what point do you think we do start to see real pricing traction? Or are we just going to let the offshore drillers have all the fun here?

Yes, James, this is Tim. I think just really following on from one of the remarks that Mark just made now that the shift of capital to the international markets, I think that's, if you like, a proof point really. If there was significant excess capacity, then we wouldn't be needing to move assets to the international market. So no, I would say that our general view is that, obviously, market-to-market, it's going to be slightly different. But in general terms, no, there's not a significant overhang of assets in the international markets today.

Our next question comes from Waqar Syed with Goldman Sachs.

Yes. My question relates also to deepwater. You had mentioned a target of growing at a rate above market growth in deepwater. I just wanted to see, as we stand today, where you are versus that growth plan and where do you see it could be a year from now.

This is Tim again. Obviously, we selected deepwater as an important growth market for us in which to invest because of the significant above-market growth rate of the segment itself. And then we set ourselves a target of growing at above the market growth rate ourselves as a company. So I think point number one is the market is really unfolding as we hoped it would. It's going to be a very strong growth segment. Secondly, we're very pleased with our positioning. And I think we're able to support our thesis that we're growing at a faster-than-market rate.

Okay. And then in terms of international shale growth, what's your view right now? We've heard some mixed views out of Poland recently. There've been some upheavals in Argentina recently. What's your current view on that? Are you seeing -- are you more positive now on international shale development or less? Could you comment on that?

Yes, I think we continue to be very encouraged. I think that we've always said that the best thing is for us to have interest in multiple markets because not all markets will be successful. We know that. But having a position in all major markets around the globe allows us to make sure that we're going to participate in those markets that are successful. We continue to feel very good about shales. I think that the truth is, though, to your question, we're probably shifting our emphasis a little bit. Argentina doesn't feel as positive as it probably was 6 months ago. But Saudi Arabia feels a lot more positive than it was 6 months ago. So I think we're starting to see, if you like, the 3 key factors of shales, the combination of the geology, the infrastructure and the pricing and regulatory environment sort of start to come to the fore. And those that have all 3 in the right measure will be the ones that'll move forward the fastest.

So beyond Saudi Arabia, how would you rank like Poland and Australia and some of the other markets?

Well, certainly, Australia is looking strongly positive. China's looking extremely positive. And I wouldn't count Poland out yet. I mean, there's a relatively small number of wells, primarily vertical wells, I would call the sort of the frac process there to be very modest in terms of trying to establish what potential productivity would be. So I think we still have a long way to go yet in that particular market.

Our next question comes from Jim Crandell of Dahlman Rose. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: My first question is in provinces, in frac-ing, where you have seen significant pressure on pricing, is there any pressure by companies that you have long-term contracts in to renegotiate the terms of your contracts at lower prices, even if you have a longer-term contract? And have you done so in any instances?

Yes, Jim, this is Dave. Let me answer that one. And the answer is in those oily based areas, the answer is no. In fact, we have gone generally back in because of guar prices or proppant prices to get price increases. But we -- for the most part, we wrote those contracts to be pretty tight. So I suspect that the pressure will come when they start to roll over, and we've got to look at what we can do. But again, we're selling efficiency, we're selling lowest unit cost because of the efficiency. And I think we are having a different kind of conversation with those customers than maybe some of our competitors would have to have. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: And that's in oil provinces, Dave, in the Haynesville, if a long-term contract customer is asking for price relief, have you done so?

You know what, Jim, there's hardly anybody left in the Haynesville but Halliburton. So you can read into that comment what you will. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: But David, your comments would relate to any -- to all instances of long-term contracts across the country that they're sacrosanct and you're not lowering prices on any?

No, I think that we -- are we rolling pricing back on existing contracts? The answer is no, the contracts that have term left on them. Those that are coming up for tender, we are having discussions about where the market pricing for long-term types of contracts are. We are not going to spot market by any stretch of the imagination. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. David, my second question, sources of mine are still saying that on international tenders, particularly in formation evaluation and particularly in deepwater, there continues to be fierce competition in pricing. Would you concur with that or put some -- what color would you offer on that statement?

No. I think as we said in the prepared remarks, any large tenders, deepwater-related that have a big formation evaluation component to them are extraordinarily competitive for a couple of reasons. One, they tend to be big dollars and they tend to be of long duration. And so they are being fiercely fought over. And I guess, I would make an editorial comment that all of the big players are equally competitive in their pricing. But as Tim indicated, I think we're winning more than our fair share of them, which is a strategy we put in front of our shareholders in our Analyst Day a couple of years ago. That was a key part of our strategy. I think it's paying off in places like East Africa, where we did have to make infrastructure and mobilization investments. But if you look at the margins we're making there today, I'm very happy with them. And I expect that, that will continue to play out as we get these projects up and going. So bottom line is I'm very happy with our market penetration in FE and in deepwater and in places where we have not operated before. And we will continue that strategy.

Our next question comes from Scott Gruber of Bernstein. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: I'm curious as to how the activity transition in North America is impacting operational uptime, looking beyond the mobilization issue. When you look out 6 months from now, will you experience an increase in operational uptime, more operations on 24 hours? Or would things be about the same from here?

Yes, I think -- this is Dave again. Again, go back to what we said. We are primarily a 24/7 operation, view our frac position in the U.S. as being more one akin to a manufacturing operation. And absent the dislocation of crews, which obviously have an impact on uptime and downtime, we don't move a crew unless we know where it's going, we know what customer it's working for and we know the price that it's going to work at. So we don't incur a cost to basically pick them up and move them somewhere without knowing what the financial impact is going to be. I would say that, that's not true with a lot of our competition who are being chased out of some of these basins, like the Haynesville, and those crews are going basically looking around for work. And that's why the transactional market pricing is so disruptive today. But as we said, that's not a market that we generally play in. So when we say we're moving a fleet, it's not going looking for work. It knows where it's going, knows who it's working for and knows the price that it's going to work at. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Got it. And does the 24-hour uptime extend to the Permian as well?

It's just starting to go there. And that's actually a great question because typically the Permian Basin has not been a market where the operators saw the need to have 24-hour operations. But we have actually gone to 24-hour operations with some of the bigger players out there and have demonstrated to them the efficiency of it. Now that's caused some disruption within the operators because they've had to change their work practices, their completion practices. But as it's gotten more competitive out there, they've seen the benefits of it. But even in a market that's traditionally not 24 hours, it's starting to basically embrace it. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Great. That's very encouraging. Last question on Canada, appreciate the color. In terms of growth CapEx in North America, I assume Canada's going to continue to be a focus as you build out that position.

No, absolutely, Scott. We -- not only -- there's some infrastructure capital that we're deploying there. We're focused on the extension of the Bakken into Southern Canada there and building out there but also helping in our infrastructure around sand logistics and things like that. We tend to view Canada -- I mean, even though it's a separate country, we tend to view capital deployed for rolling stock and things like that as a bit fungible between the U.S. and Canada. And so during breakup, oftentimes we'll move things back and forth to make sure that we maintain very high efficiency levels for those crews.

Our next question comes from Bill Herbert of Simmons & Company. William A. Herbert - Simmons & Company International, Research Division: A question on the cost inflation. Dave, for a couple quarters here, we've been talking about the lead lag here between incurring costs from vendors and being able to pass them through to the customer and with increasing difficulty, I guess, in dry gas plays. But in due course, you seem to foreshadow an ability to do that. I'm curious as to actually with regard to the cost of the raw material itself, guar, proppants, what-have-you. At what point do these headwinds with regard to margins become tailwinds with regard to the raw material itself becoming less expensive with more supply?

Yes. I think, certainly on guar, we've not reached that point. And yes, we clearly are able to, on things like guar, with some lag, get that cost passed through to our customer. The problem with guar, it's probably the fastest-moving commodity price that I've ever seen. I mean, basically, we might give a quote today that's 10% higher than a quote we would've got last week on it. So it is such a dynamic that we don't like to and don't want to go back to our customers multiple times to get price increases. So we try to get it stabilized within a certain area then go back to the customer and basically put it through as a pass-through item. But that is the one, because of the scarcity at this moment in time -- and we do believe that it's actually a bit of a spot price scarcity due to sort of the growing season for guar, which is primarily grown in India, and when the new crop will become available which should be in the fall, and then we see maybe see some of the scarcity going away. And also obviously, we, like the rest of industry, are looking for alternatives to guar, and we are having some customers accept either lower-grade guar or alternatives to guar that, while maybe not getting the well response they want, at least they are getting something at a cheaper price. William A. Herbert - Simmons & Company International, Research Division: Got you. And do you think -- I mean, I know it's difficult to sort of foreshadow at this juncture. But do you think it's a reasonable expectation to expect that the guar cost inputs in 2013 will probably be less than what they are today?

Based on everything we know right now, that's a reasonable expectation.

Yes. I think also, Bill, the fact of the matter is, is that guar substitutes become attractive at a certain guar price. We're at that price right now. So guar substitutes, whether or not that's Halliburton's CleanStim technology, for example, which is certainly a substitute which has been used effectively in a number of basins, including the Eagle Ford, or other substitutes, will become effective and will essentially create some sort of ceiling on the price of guar. William A. Herbert - Simmons & Company International, Research Division: Got you. Second question, I mean, everybody, I guess, justifiably seems to be focused on what's going wrong as opposed to what can go right in a category of what can go right. With regard to the likely uplift in activity, in the Wolfcamp activity, plus a step change increase in service intensity, coupled with the ongoing evolution of the Utica and other plays, how do you think the industry is positioned today from a capacity standpoint to meet that demand, call it, 2 or 3 years down the road?

Yes, I think a couple of points there, Bill. I think number one, I mean, clearly, the industry has a history of responding to the need. I don't particularly see that as being a primary concern. And so I think that if you take a look at where we are today as we outlined, what we're planning on is a modest single-digit increase in activity through the year. Now that's the basis for the guidance that we provided. And clearly, there is a scenario where we have a significantly increased volume of activity in oil-based plays. If that takes place, then clearly, we have a much more robust outlook than we currently have. But we provided you a scenario based on our best guess, which is [indiscernible]. William A. Herbert - Simmons & Company International, Research Division: Got it. And then last one, you touched on this, but I didn't get a sense as to order of magnitude. Frac of the Future initiatives, one, are they tracking as expected and targeted? And two, when do you expect those to begin to exert a significant impact with regard to your North American profitability?

So there are a number of elements to Frac of the Future, all aimed at a variety of elements around reduced personnel, reduced capital deployment, et cetera, and improved efficiency. Probably the largest single element of that is the rollout of our Q10 pump, which is now rolling off the line. And we will make that together with our new blending and storage capacities. And we have a deployment plan which will give us the ability to compare very effectively between existing fleets and our new Frac of the Future fleets, so we can get a real good handle on both capital deployment and people deployment. We'll see those roll out during the course of this year, Bill. And towards the end of this year, we'll have a very -- start to see an impact in key basins, where they're deployed.

I was also going to say at the back-office initiatives, the mobility plans are all designed to roll out late Q2 and Q3, which really means that you're going to see the meaningful part of the impact in 2013. William A. Herbert - Simmons & Company International, Research Division: And the leaning out of the frac crews, we still expect to see an overall sort of reduction of about 25% on average with regard to the employees attributable to your frac crews?

Yes, Bill, that's still the target. Part of that will be achieved through the rollout of these new pumps and the blending units and other things that allow us to do less maintenance out on location. The other thing will also be the mobility plan helps us in achieving more of our remote operations initiative, which again will be later in 2013. But in particular areas such as the gas basins, our guys are very focused on leaning out those crews as we speak as the work provides for it. Other places, we're still scrambling as you might imagine, and it's all hands on deck.

Our final question comes from Doug Becker of the Bank of America.

I'll hit the international side a little bit, but it seems like results are off to good start. What do you think the greatest risk to meeting margin expectations in the high teens by the end of the year are? Is it more mobilization? Is it just more pricing, never picking up? How would you characterize that?

This is Tim. I would say that one of the things that we have collectively been disappointed with is essentially the growth of rig count and growth of activity during the course of the last 12 months. Year-on-year, we're only up about 2% in terms of rig count. So I would say the biggest single risk probably is more around ensuring -- well, I said not that we can ensure it, but it's more around the continued expected progression of rig count through the balance of the year than any other factor. It looks good right now, but we have been disappointed before by the amount of growth.

And it looks like we saw a relatively modest decline in revenue and margin in Europe/Africa/CIS. Is the first quarter a good base for us to be thinking about a bit of a recovery, a seasonal recovery in the second quarter in that market?

Well, clearly, there'll be seasonal recovery. You have to recall that the weather in Northern Europe on the North Sea was incredibly bad this year, probably worse than it's been in a long time, the exact total opposite from what we experienced in North America. So I think that the seasonal impacts were larger than we had seen in some prior years, which probably is part of what you've seen and maybe missing your potential -- your particular expectation. But I think in that regard then, we should see a better seasonal recovery from some of those areas as we go into Q2 and Q3.

That's what I was getting at. And then just in Latin America, any quantification of what the mobilization might be in the second half? Are we talking 100, 200 basis point drag or something along those lines?

I think a little too early to say right now. We can provide some additional guidance on the next call.

Okay, Sean, we're ready to close out the call.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.