Kelly Youngblood - David J. Lesar - Executive Chairman, Chief Executive Officer and President Mark A. McCollum - Chief Financial Officer and Executive Vice President Timothy J. Probert - President of Strategy and Corporate Development

John David Anderson - JP Morgan Chase & Co, Research Division James C. West - Barclays Capital, Research Division Waqar Syed - Goldman Sachs Group Inc., Research Division James D. Crandell - Dahlman Rose & Company, LLC, Research Division Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division William A. Herbert - Simmons & Company International, Research Division Douglas L. Becker - BofA Merrill Lynch, Research Division

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? David J. Lesar: 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 our fourth quarter call, we talked about 8 frac fleets moving from primarily natural gas plays to liquids plays. We now have an additional 5 fleets that have moved or are in the process of moving this quarter. Due to the stability of oil prices, oils in the liquid-rich plays are generating higher returns for our customers. This shift is very positive for us as completing these wells requires higher levels of service intensity due to the advanced fluid and completion technologies, which creates an additional opportunity for us to differentiate ourselves from our competition. While these moves are beneficial to us in the long run, they do not come without a short-term impact on our margins. With spot natural gas prices down approximately 50% from this time last year due to the resiliency of natural gas productions in a very mild winter, so at the current prices, we expect to see further declines in the natural gas rig count until we begin to see a meaningful decrease in production levels. Over time, we believe any future weakness in natural gas rig count will be offset by an increase in oil and liquids-rich activity, resulting in an overall yearly percentage increase in the U.S. rig count in the mid-single-digits. Also on our last call, we provided our outlook for North America margins for the first quarter. Our revenue was strong this quarter due to better-than-expected activity levels. But our margins were just below our expectations, given that the drop-off in natural gas rig count was more pronounced than we anticipated. Continued significant cost inflation also negatively impacted our margins. As a reminder, there is often a delay between vendor price increases and when we are able to pass these increases to our customers. In the natural gas basins, in particular, this is becoming more difficult and we are working with our vendors for price relief. However, this will take time and may continue to impact margins throughout the remainder of 2012. As we renew contracts and win new work, we expect to see frac pricing become more challenging, but the impact will vary by basin. The dry natural gas basins will be the most challenged, followed by those more easily accessible oily basins that are located close to natural gas basins, such as the Eagle Ford. We expect pricing pressure in some of these markets in the near term but believe that these pressures will decline over the remainder of the year. On the other hand, our other product service lines continue to have relatively stable pricing. I would like to review some of the key differentiators that I believe make us unique and should continue to enable us to outperform our competition in North America. First, I want to recognize our supply chain organization, whose efforts over the past few years have positioned us well for the current industry challenges. In the 2009 downturn, when many of our peers halted new investment, we recognized the structural changes that were incurring in the North American market. We continued to manufacture new equipment, build logistical infrastructure and develop strong relationships with key suppliers and lock in critical supply agreements. In some cases, we actually provided funding to assist our suppliers with their own internal expansion needs so they could meet our supply requirements. Our leading market position and long-term commitment to North America have helped us secure supplies for key commodities in a very tight market, which has enabled us to minimize supply and logistical disruptions to our customers. The shift of rigs from natural gas to oil has amplified supply chain issues for the industry. We recognize that we are not immune to these challenges. However, we believe our supply chain organization gives us a distinct advantage that should allow us to effectively outperform our competition in 2012. To make our logistics process more efficient, we have been constructing transloading facilities in key basins that transfer materials directly from railcars to truck or storage. This reduces our overall transportation to merge costs and improves our efficiencies and allows us to better serve our customers. We strongly believe we will continue to be able to provide our customers with the proppants, guar and other materials they require to be successful as they expand their activities toward oil. I do not believe that many of our competitors can make this statement. In particular, guar, which is a thickening agent used in certain fracturing treatments, is expected to be in scarce supply this year. And although we believe we have secured enough supply for our customers, there have been significant cost increases in guar which are negatively impacting our margins. We are currently working to recover this increased guar cost from our customers. To give you some idea of the magnitude of this increase, the guar gel system cost alone can now represent more than 30% of the total frac price to our customer in certain basins. Additionally, we expect to see some vendor price relief in the second half of the year on our proppant costs. Also customer relationships and mix are very important differentiators. Over the past few years, we have carefully aligned ourselves with operators that are running large-scale operations and whose focus is on reliability and value and not just price. We believe we have successfully proven that our superior service quality, reliability and efficiency make us the preferred service company. Price competition today is most pronounced in the transactional market, which we have and will continue to generally avoid. We acknowledge that we are not immune to pricing pressures either. But as contracts renew, we believe we will continue to get superior margins due to our customer mix. In addition, a high percentage of our crews provide 24/7 operations. This is a win-win scenario for us and our customers. Our customers recognize our ability to provide them with a manufacturing-type efficiency model, which ultimately reduces their overall completion cost. This generally enables us to obtain superior margins compared to our peers. Through this efficiency and incremental capacity, we are now able to provide services to customers that we could not get to in the past, and I believe will actually result in a market share increase without us having to discount price on a relative basis. And lastly, we continue to expand our capabilities and drive efficiency through technology and redesign of our operations. Our Frac of the Future initiative is a perfect example of how we are staying one step ahead of the competition. We have just rolled out our first series of Q10 pumps, which we believe are the most efficient and lowest-maintenance pumps in the industry. We are also deploying smartphone technology to automate many of the tasks that are now performed manually in the industry today, which we believe will improve efficiency, reduce our operating costs and reduce working capital requirements. We are also working to optimize crew size and centralize functions to be more cost-efficient. As we have highlighted in the past and will continue to highlight, these and other strategic costs have an immediate negative impact on our earnings. However, they are a future investment in continuing to differentiate ourselves in the market. Turning to the Gulf of Mexico. We remain optimistic about the recovery of activity and believe that margins will continue to increase as our customers adapt to new regulations and industry efficiency improves. The increase in permit approval should lead to additional deepwater rigs arriving throughout 2012. Our first quarter margins in the Gulf were lower than the prior quarter due to a different mix between drilling and completion-related revenue activities, mainly driven by customer delays of certain completions, an area where we hold the highest market share. We are very optimistic about the future work we see in the Gulf and we have secured additional directional drilling, drilling fluids, wireline and completion work on a number of the new deepwater rigs coming into the Gulf and some of the rigs that are going back to work in the next few quarters. So to summarize North America, we believe increased activity of our customers due to the strong liquids prices, access to capital and increase in service intensity are supportive of a healthy market for us in 2012. However, we expect continued short-term inefficiencies and, therefore, downward pressure on margins in the near term due to the shift in our equipment, commodity price mix and pricing pressure and the spring breakup in Canada. We currently expect these transitory disruptions to decrease the second half of 2012. Also to be noted, I believe the growing scope of our Canadian business is underestimated due to the size of our U.S. business. I'm pleased to say that Canada is expected to deliver a $1 billion revenue stream for us this year and is a good contributor to our North American profitability. Therefore, we expect to be impacted by the spring breakup in this year's second quarter in Canada more than we have been in the past. So although 2012 will be challenging for North America, I believe it will just be another opportunity for us to differentiate ourselves from our peers and continue to drive our strategy of superior growth, margins and returns. Now turning to our international results. They were basically in line with our previously stated expectations. We are very optimistic about our Latin America business this year. Latin America posted solid results for the first quarter, taking into consideration the typical first quarter impact of lower consulting and software sales as compared to the fourth quarter. We continue to see shale development opportunities evolving. We are excited about leveraging our expertise in unconventional resources to help our customers unlock the potential of these plays. We delivered great production results on our Remolino field lab in Mexico, and Tim will cover that in a few minutes. Based on tendered prices that we have seen, we also believe that we are well positioned to win significant incremental work on the recent bids for Brazil in wireline, directional drilling and testing. As a result, we expect to incur mobilization costs in the second half of 2012 that will temporarily impact Latin American profitability. Brazil was the largest contributor to our operating income increase over the first quarter of 2011 in Latin America and we expect it to continue to grow rapidly. Our strategy in the Eastern Hemisphere is also playing out as expected, as is evident by our revenue growth in excess of the rig count growth. Eastern Hemisphere revenue was up 14% from the first quarter of 2011. We continue to make progress in markets that had been negatively impacting our results and are optimistic about activity levels expanding into the second half of 2012. For instance, in East Africa, we continue to see activity levels increase. While startup costs had a negative impact on margins in 2011, we are now seeing our deepwater investment strategy begin to pay off in this important growth market. We also took action the last few quarters to improve our profitability in our operations in the U.K. Our efforts are now paying off there. Despite weather-related seasonality, we saw stronger operational results and are now generating healthy margins in that market. In Iraq, we continue to run 5 rigs and expect to add additional rigs and workover rigs in 2012, enabling us to improve our profitability as activity levels increase. Overall, we remain enthusiastic about the future of our Iraq operations and are pleased to be getting the past issues behind us. In Libya, production is also coming back online. However, we are still awaiting well-defined operational plans from our customers. We do not expect to approach pre-2011 activity levels in Libya until late 2012 or 2013. So our view of the international markets has not changed at all. We anticipate international pricing will continue to remain competitive, particular in regard to larger projects being tendered. We continue to expect our margin improvement through 2012 as new projects ramp up. We introduced new technology and continue to improve our results in those markets, where we have made strategic investments and secured key wins over the past few years. To give you more granularity on the financial results, I'll turn it over to Mark. Mark A. McCollum: 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 and Production revenue declined $38 million or 1%, primarily due to seasonally lower Completion Tool sales and first quarter weather disruptions in the North Sea, Eurasia and Australia. Completion and Production operating income declined 5%, primarily due to North American inefficiencies associated with equipment relocations and other factors that Dave mentioned earlier. Looking at Completion and Production on a geographic basis. North America revenue increased by 1%, driven by increased activity in the U.S. oil and liquids-rich basins and Canada. This was partially offset by activity decreases in the U.S. dry gas basins in the Gulf of Mexico. Operating income declined 7% due to equipment relocations, cost inflation and stimulation pricing. In Latin America, Completion and Production posted a 2% sequential decrease in revenue due to reduced submitting activity in Colombia and Mexico and lower Completion Tool sales in Brazil and Trinidad. Operating income grew by 8% as a result of increased Boots & Coots activity in Mexico and Venezuela. In Europe/Africa/CIS, Completion and Production revenue decreased 8%, primarily related to lower activity in the North Sea and Eurasia due to the normal first quarter seasonal weather impact. Operating income increased 30% due to increased Boots & Coots profitability throughout almost all of Africa, along with higher cementing activity in Mozambique. Also contributing to the profit increase was higher production enhancement and cementing activity in Libya, along with a collection of some of the receivables that were written off there in early 2011. This was partially offset by seasonally lower activity in the North Sea and Russia and lower cementing and production enhancement profitability in Angola. In Middle East/Asia, Completion and Production revenue decreased by 7%, primarily due to seasonally lower Completion Tool sales across the region and seasonal weather issues in Australia. Operating income increased 2% due to increased cementing and production enhancement activity in Oman and additional Boots & Coots activity in Iraq, Saudi Arabia, Thailand and Indonesia. In our Drilling and Evaluation division, revenue and operating income decreased primarily due to seasonally lower software and direct product sales in the first quarter as well seasonal weather disruptions in the North Sea, Eurasia and Australia. In North America, Drilling and Evaluation's revenue and operating income were up 2% and 7%, respectively, due to higher activity in drilling fluids, directional drilling and increased drillbit sales in U.S. land, as well as higher wireline activity in Canada. These increases were partially offset by lower software sales and decreased drilling activity in the Gulf of Mexico due to scheduling delays that we expect to make up next quarter. Drilling and Evaluation's Latin America revenue and operating income decreased primarily due to seasonally lower software sales and the normal first quarter delay in obtaining contract approvals for consulting services and software sales in Mexico, as well as lower directional drilling activity in the first quarter in Mexico. In the Europe/Africa/CIS region, Drilling and Evaluation revenue and operating income were down due to the seasonally lower software sales, seasonal weather impacts in the North Sea and Asia and lower drilling activity in Algeria and Angola. This decrease was partially offset by increased drilling activity in Sub-Saharan Africa. Drilling and Evaluation's Middle East/Asia revenue and operating income decreased due primarily to lower first quarter product sales in Asia that were partially offset by increased drilling activity in Saudi Arabia and higher project management activity in Iraq. Our results for the first quarter reflect a $300 million accrual in Corporate and Other expense for estimated loss contingencies related to Macondo. At the request of the court, in late February, we participated in a series of discussions with the magistrate judge relating to whether the multidistrict litigation or MDL could be settled. Although those discussions did not result in a settlement, we've accrued $300 million, reflecting our current estimate of the loss contingencies that are probable relating to the MDL. Our decision to take an accrual now in the amount we have recognized are based on our assessment of all of the facts and circumstances regarding the litigation at this point in time. Although we continue to believe that we have substantial legal arguments and defenses against any liability and that BP is required to indemnify us for any losses we may ultimately incur, we've determined that we can no longer conclude that a probable loss associated with the MDL is 0. There are other contingencies related to the Macondo well incident that are reasonably possible and for which a reasonable estimate cannot currently be made. We're constantly monitoring and evaluating developments relating to the MDL and the other Macondo-related lawsuits and investigations. And it's possible that we may adjust our estimate of these loss contingencies in the future as new information becomes known. Apart from the Macondo-related charge, our Corporate and Other expense came in lower than expected in the first quarter due in large part to the timing of expenses related to our continued investment in our initiative to reinvent our service delivery platform in North America and to reposition our supply chain, manufacturing and technology infrastructure to better support our projected international growth. The expense related to these initiatives during the quarter totaled approximately $23 million, which was slightly less than we had expected. However, the activities behind the cost are on schedule and we continue to ramp up through 2012. We anticipate the impact of these investments will be approximately $0.02 to $0.03 per share after-tax in the second quarter. In total, we anticipate that corporate expenses will range between $110 million and $115 million per quarter for the remainder of 2012, which, for the total year, is in line with our previous guidance. We anticipate that our CapEx for the year will still be in the range of $3.5 billion to $4 billion. But we've decided to defer some of the North American pressure pumping equipment deliveries into 2013 that were originally planned for 2012. In addition, more capital will be allocated to international projects that we've recently secured or expect to win in the next couple of quarters. We're also allocating a significant amount of capital for infrastructure needs throughout the globe and in support of growth of our recent acquisitions. And finally, our effective tax rate was 32.3% for the first quarter, but the average rate was helped by the higher U.S. tax rate that was applied to the Macondo-related charge. We currently expect the full year 2012 effective tax rate will be approximately 33% to 34%, in line with the normalized rate we saw in the first quarter. Tim? Timothy J. Probert: 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 initial production above 3,800 barrels a day and delivered cumulative production equivalent to over 20 average wells in the region. This is a model which is being applied in other mature assets in Latin America, Africa, the Middle East and Asia, and one which we expect to have a positive business impact in the latter half of this year and into 2013. Halliburton's EquiFlow Autonomous Inflow Control Device is a key technology to facilitate mature asset development and has been introduced in several wells in Latin America and the Middle East. It's a 2012 Offshore Technology Conference Spotlight on New Technology Award winner and is a simple, reliable device developed to address problems of unwanted water or gas production and solves the problems of inefficiency in current inflow device designs. International unconventional development continues to provide increasing levels of encouragement to us. Halliburton has active frac spreads in Poland, Argentina, Mexico, Australia, Saudi and elsewhere, which is allowing us to build the requisite basin and subsurface expertise necessary for successful execution and is building a strong foundation for future growth. We're also pleased with the recently signed Framework Agreement between PETRONAS Carigali and Halliburton for the evaluation and development of global shale resources. This collaboration is expected to leverage our technology and expertise to enable PETRONAS to quickly gain experience in shale development. We plan to work with them to set up a Shale Technical Centre of Excellence in Kuala Lumpur. Dave? David J. Lesar: 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? Timothy J. Probert: 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. Mark A. McCollum: 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? Mark A. McCollum: 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? Timothy J. Probert: 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? Mark A. McCollum: 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. James C. West - Barclays Capital, Research Division: 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. Mark A. McCollum: Yes. It's sort of the trend toward the end of the year is what I'm alluding to. James C. West - Barclays Capital, Research Division: 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? Mark A. McCollum: 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. James C. West - Barclays Capital, Research Division: 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? Timothy J. Probert: 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. Waqar Syed - Goldman Sachs Group Inc., Research Division: 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. Timothy J. Probert: 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. Waqar Syed - Goldman Sachs Group Inc., Research Division: 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? Timothy J. Probert: 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. Waqar Syed - Goldman Sachs Group Inc., Research Division: So beyond Saudi Arabia, how would you rank like Poland and Australia and some of the other markets? Timothy J. Probert: 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? David J. Lesar: 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? David J. Lesar: 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? David J. Lesar: 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? David J. Lesar: 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? David J. Lesar: 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? David J. Lesar: 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. Mark A. McCollum: 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? David J. Lesar: 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? Mark A. McCollum: Based on everything we know right now, that's a reasonable expectation. Timothy J. Probert: 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? Timothy J. Probert: 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? Timothy J. Probert: 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. Mark A. McCollum: 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? Mark A. McCollum: 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. Douglas L. Becker - BofA Merrill Lynch, Research Division: 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? Timothy J. Probert: 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. Douglas L. Becker - BofA Merrill Lynch, Research Division: 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? Mark A. McCollum: 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. Douglas L. Becker - BofA Merrill Lynch, Research Division: 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? Timothy J. Probert: 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.