David Lesar – Chairman of the Board, President and Chief Executive Officer Mark McCollum – Executive Vice President and Chief Financial Officer Tim Probert, President Global Business Lines and Corporate Development Christian Garcia – Vice President, Investor Relations

Dan Boyd – Goldman Sachs Bill Herbert – Simmons & Company David Anderson – J P Morgan Scott Gruber – Sanford Bernstein Kurt Hallead – RBC Capital Ole Slorer – Morgan Stanley Angie Sedita - UBS James Crandell – Barclays Stephen Gengaro - Jefferies

Good day, ladies and gentlemen, and welcome to Halliburton’s Second Quarter earnings call. At this time all participants are in a listen-only mode. Later we will conduct a question and answer session and instructions will follow at that time. (Operator instructions) As a reminder this conference is being recorded. I would now like to turn the conference over to your host today, Christian Garcia, Vice President Investor Relations. Please begin.

Good morning, and welcome to the Halliburton Q2 2010 conference call. Today’s call is being webcast and the replay will be available on Halliburton’s website for 7 days. The press release announcing the Q2 results is available on the Halliburton website. Joining me today are Dave Lesar, CEO; Mark McCollum, CFO; and Tim Probert, President Global Business Lines and Corporate Development. In today’s call, Dave will provide opening remarks, Mark will discuss our overall financial performance and liquidity position, and Tim will provide comments on our operations and business outlook. We will welcome questions after we complete our prepared remarks. I would like to remind our audience that some of today’s comments may include forward looking statements reflecting Halliburton’s views about future events and their potential impact on performance. These matters involve risks and uncertainties that could impact operations and financial results, and cause our actual results to differ from our forward looking statements. These risks are discussed in Halliburton’s Form 10K for the year ended December 31, 2009; Form 10Q for the Quarter ended March 31, 2010; and recent current reports on Form 8K. Note that we will be using the term “international” to refer to our operations outside the US and Canada, and we will refer to the combination of US and Canada as “North America.” Dave?

Thank you, Christian, and good day to everyone. Overall I’m very pleased with our Q2 results. Our total revenue of $4.4 billion was 26% higher than the prior year, and our first year-on-year increase we’ve experienced since the Q4 of 2008. We were able to leverage our expanded market position to benefit from the significant increase in US land activity and the seasonal recovery in the international markets. Our operating income grew 60% from the prior year, led by more than a 400% increase in North American profitability. Let me talk first a little bit more about North America. North America was our stellar performer in the Q2, with sequential revenue increasing 24% versus US land rig count growth of 13%. This is the first quarter that our sequential revenue increase outpaced rig count growth since the recovery began last year. Operating income improved over 90% sequentially, despite the negative earnings impact of the Canadian seasonal slowdown and the deepwater drilling suspension in the Gulf of Mexico. The gas-directed rig count rose 8% during the Q2. Gas operators are benefiting from productivity gains driven by improved drilling and completion times that lower their breakeven thresholds and enhance their returns. Also, drill to hold activity continues to also influence gas-directed activity. The US oil-directed rig count grew 19% over Q1 levels, buoyed by stabilized commodity prices for liquids. Oil rigs now number close to 600 in the US, a level which we have not seen since the early ‘90s. The continued rebound in oil- and gas-directed activity in the Q2 led to increased utilization levels for our equipment and provided us opportunities to increase prices for several of our product lines, led of course by our stimulation business. We have also experienced smaller increases for directional drilling, cementing, and drill bits, as our ability to integrate services together creates a proposition that adds value to our customers. In this upturn, however, price increases have not been uniform across all the various land basins in the US, because we’re taking a different approach in today’s market environment. We are working with customers to understand their production economics, developing equipment efficiency models and setting prices at rates that allow them to earn the returns that they require while enabling us to also generate an appropriate return for our capital investment in that particular basin. I see this as a win-win situation, as it allows our customers to keep their rigs running but does not force us to leave a particular basin to seek higher returns for our equipment. Across this spectrum, pricing power is highest in the oil and liquid rich basins, and lowest in the conventional dry gas basins, with dry gas shale plays somewhere in between. Utilization levels for our equipment have now surpassed those at the rig count peak in the Q3 of 2008, and are fast approaching levels not seen since the fall of 2006. Utilization levels are highest in the plays with the strongest growth, such as the Bakken and the Eagle Ford, where we have significantly expanded to 24 hour operations. Discussions are underway with some operators regarding longer-term contracts, and we are experimenting with a few of these. These contracts may contain take-or-pay, or standby rate provisions, which can provide a certain level of revenue stability for US land operations. We are currently evaluating these types of contracts, but I am not yet convinced that they generate the highest returns for our equipment over a full business cycle, and we are not pursuing these arrangements aggressively at this point in time. In the Q2 interest in liquid-rich gas plays remained high because of the relative stability of oil prices and improved operator returns on these resources. These plays now account for 10% to 15% of total rig count, and while they are typically counted as gas rigs they are dependent economically on commodity prices for liquids. Their continued development, however, generates incremental gas production in an already oversupplied gas market and may exert additional downward price pressure for natural gas in the coming months. One of our key strategies in the downturn was to build market share based on our strong belief in the long-term potential of the North American market, and I believe we were very successful in that effort. Our strategy now is to defend this expanded market position. We have been, and we will continue to do this by deploying sufficient incremental capacity to meet the robust demand for our services. We believe the actions we are taking will strengthen the long-term health of our franchise. So even though we see potential for additional upward pricing improvements, these increases will moderate and we expect our sequential revenue growth will more match the rig count in the coming quarters. Any improvement in our margins may also be limited due to increased oil field costs, as we are now seeing significant inflation creep into our US cost structure in such areas as higher commodity, freight, and labor costs. Let me spend a few moments discussing the situation in the Gulf of Mexico. The tragic incident that occurred on April 20th and the subsequent suspension of deepwater drilling we believe will usher in a new regulatory climate and have a profound impact on how future deepwater drilling is performed. Uncertainty around new drilling requirements and the extent of activity time during and after the drilling suspension will influence the future actions we will take in the Gulf. In addition to the impact of the contraction in the deepwater Gulf, we are also seeing considerable delays in shelf drilling as a result of the new requirements for shallow water permits. I believe these delays combined with the drilling curtailment in deepwater will cause E&P spending to shift onshore and outside the US, to enable operators to meet their production targets. Gulf activity may also remain restrained after the drilling suspension as operators need to adjust to more stringent drilling and permitting requirements. Further, I do not believe that the deepwater offshore rigs that were mobilized to international locations during this suspension will return to the Gulf for some time, if at all. Based on this scenario, we’re taking the following actions in our Gulf of Mexico business: First, we are rationalizing our equipment capacity in the Gulf. We are transferring drilling and down-hole wire line tools to international locations to support new projects that we have already won. Cementing, mud logging and wire line skid units are all rig-based, and typically their transfer will go with the rig as it leaves the Gulf of Mexico. We have two stimulation vessels that have been working in the Gulf of Mexico and will continue to work in the shallow water, and we intend to keep them in the Gulf during this period. At this point, overall equipment movements are just starting and it is too early to tell if this will meaningfully impact the pricing dynamics in the international markets. We also currently have an aggressive hiring program in our US land operations, and we are transferring a significant number of our Gulf field personnel to satisfy this need. In addition, we are relocating some of our engineering personnel to the international offshore market to retain our extensive deepwater talent. In the near term we intend to keep our infrastructure intact in the Gulf of Mexico. This obviously will impact our short-term results but will allow us to remain competitive once activity resumes in the marketplace. Despite these short-term impacts, the events in the Gulf of Mexico have not at all stifled our enthusiasm for increased global deepwater activity in the upcoming years. Contributions from the service sector can play a valuable role in developing new technology, innovations, and best practices to help our customers operate safely and efficiently in these challenging conditions, and I believe will generate a corresponding increase in service intensity. Tim will talk about this a little bit more later. Let me turn now to our international business, starting with Latin America. Latin America posted strong improvement from the Q1’s weak results. Brazil continues to stand out in terms of revenue growth. In the Q2 our Brazil operations generated sequential double digit revenue increases and year-on-year growth of close to 30%, driven by our well construction product lines. In the past year we have made significant strides in solidifying our market position in Brazil, with wins in directional drilling, wire lines, fluids, testing, and completions. Additionally, we have and continue to make infrastructure investments in Brazil. We believe that these investments, combined with our unique deepwater capabilities, will ensure that we continue to be well positioned to benefit from Brazil’s long-term growth prospects. Mexico also had improved results in the quarter; however, we believe that the current quarter activity levels for Mexico are unlikely to be sustainable. Our customer has informed its service providers that due to budgetary constraints they will be reducing the number of rigs allocated to Chicontepec for the remainder of the year to about two rigs per major service company. We are currently operating on four rigs and were about to add a fifth. Additionally we anticipate activity in the Burgos basin to remain depressed given the continued weakness in natural gas prices. To counteract this we have started adjusting our Mexico’s cost structure and are transferring equipment to other locations in Latin America and the US. As a result we may incur some restructuring charges in Q3 to account for these actions. For the remainder of the year we see strong growth from Brazil, Columbia and hopefully Argentina, which may offset weaknesses in Mexico and Venezuela. Given the unevenness of the growth prospects in these countries, we are not anticipating a material net improvement in overall revenues and margins for our Latin America region in the second half of the year. Now for the Eastern Hemisphere. Eastern Hemisphere revenue and operating income increased 9% and 23% sequentially, while incremental margins were 36%. Our Q2 results reflect a seasonal rebound from bad Q1 weather experienced in Russia, China, Australia, and Indonesia. Despite the strong rebound in our Eastern Hemisphere results, we are cautious about a number of factors that may impact the rate of the industry’s growth the rest of the year. Continued concerns around the current pace of economic recovery and corresponding energy demands are causing some of our customers to reevaluate their execution plans for the second half of the year. Furthermore, based on the Gulf spill, international customers are revisiting their deepwater processes and that also is causing short-term delays in the startup of certain projects. Theses factors, together with continued, very competitive levels of international pricing, may lead to a lower ramp up of revenues and margins in Q3, with stronger growth resuming toward the end of the year. So, our Q2 results show the successful execution of our strategy, of balancing our geographic, technology, and services portfolio. In the second half of 2010 and beyond we will continue to increase our exposure to the industry’s highest growth markets, like deepwater and unconventional resources to optimize our growth and returns. Now let me turn it over to Mark, and he’ll get into a little more detail on the financial results.

Thanks, Dave, and good morning everyone. As I go over our financial highlights I’ll be comparing our Q2 results sequentially to the Q1 of 2010. Our revenue in the Q2 was $4.4 billion, up 17% from the previous quarter. Total operating income for the Q2 was $762 million, up 70% from the previous quarter. All of our regions registered double digit increases. International margins in the Q2 improved to 16%, as all of our international regions registered steady improvements from Q1 levels. For North America margins in the Q2 increased from the prior quarter due to strong activity and improved pricing across most basins, with overall incrementals exceeding 50%. North America margins were generally consistent month to month throughout this quarter. Now I’ll highlight the segment results. Completion and production revenue increased $429 million or 22%, and operating income more than doubled with solid contribution from all regions. Looking at completion and production on a geographic basis, North America revenue increased by 27%, while operating income grew by 126% from better activity and pricing. Increased completions intensity, particularly in unconventional shale basins, has led to high utilization rates that are exceeding levels experienced during the 2007-2008 time period. In Latin America, completion and production revenue increased by 5% and operating income increased 17%, primarily from improved performance in Mexico, Columbia, and Argentina. In Europe Africa CIS completion and production revenue and operating income increased 19% and 144% respectively, due to strong production enhancement activity in The Congo, Algeria, and the North Sea, and increased completion tool sales in Norway and Nigeria. In Middle East Asia completion and production posted sequential increases in revenue and operating income of 14% and 76% respectively, due to strong completions in production enhancement activity in Saudi Arabia, Australia, and Southeast Asia. In our Drilling and Evaluation Division revenue and operating income increased by $197 million and $48 million respectively, primarily as a result of higher activity across all our regions except Europe Africa CIS. In North American Drilling and Evaluations revenue and operating income increased 17% and 41% respectively, as most of our product service lines continue to benefit from increased horizontal drilling, which grew approximately 18% from the Q1. Current horizontal rigs represent over 50% of total US rigs, and are now about 33% higher than the levels we saw in the peak rig count of the Q3 of 2008. Drilling and Evaluations Latin America revenue and operating income increased 21% and over 224% respectively, from higher testing activity in Brazil and increased software sales and project activity in Mexico. In the Europe Africa CIS region drilling and evaluation revenue and operating income were down $13 million and $38 million respectively, due to lower activity in the North Sea and certain locations in West Africa, which were partially offset by the seasonal recovery in Russia. And Drilling and Evaluations Middle East Asia revenue and operating income were up 13% and 14% respectively, from higher drilling activity in Saudi Arabia and Indonesia, increased fluids revenues in Australia, and from wire line service in Iraq. In the Q2 we completed seven wells relating to our Ghawar project in Saudi Arabia as scheduled. This quarter’s effective income tax rate was 30%. It’s lower than our previous guidance due to the favorable impact of an R&D credit settlement that we received late in the quarter. We continue to forecast that our effective income tax rate for the balance of the year will be somewhere between 32% and 33%. Dave discussed our current plans to address the deepwater drilling suspension in the Gulf of Mexico, but I’d like to provide some additional color if I may. Our Gulf of Mexico region business represented approximately 6% of our total revenues for the first half of 2010. We have said before that roughly 65% of our Gulf of Mexico region business relates to deepwater. We have also said that labor costs represent about a third of our total cost structure. Based on our current assumptions on activity levels during and after the deepwater drilling suspension, we have started redeploying to other markets close to 20% of the 2,200 employees serving in the Gulf of Mexico region, as well as some of our other assets. Despite our mitigation efforts we're currently estimating that the drilling suspension will impact our earnings by somewhere between $0.05 and $0.08 per quarter starting in the Q3, and continuing for a few more quarters. As all of you would appreciate, the situation in the Gulf continues to evolve and there will continue to be some level of uncertainty around the full impact of the drilling suspension on our future financial results. With respect to the Deepwater Horizon incident, we continue to be confident that Halliburton performed all work with respect to the Macondo well in accordance with BP’s specifications for its well construction plan and BP’s instructions. Our contract with BP Exploration provides specific indemnification of Halliburton for claims and expenses relating to situations just like the Macondo incident. However, this obviously could be subject to challenge by various parties. In addition, while some have questioned BP’s financial survivability, we do not believe this is a likely outcome. But clearly our indemnification is dependent on BP’s financial ability to perform under its contractual indemnity obligations. As you know there are also a number of announced Congressional and other governmental investigations that are currently ongoing. We are and will continue to cooperate fully with all these efforts. However, because of these investigations as well as various lawsuits pending on this matter, we will not be taking further questions regarding the Deepwater Horizon incident during this call. Tim?

Thanks, Mark, and good morning everyone. As Dave discussed we remain very positive about the long-term prospects of deepwater activity despite the recent events in the Gulf of Mexico. I’ll provide a few additional observations on the development of these resources. The US has had around 15% of the world's 242 floating rigs, the third largest market after Asia/Pacific and Latin America. IHS data indicates that over the last five years deepwater and ultra deepwater accounted for some 40% of global new discoveries, with the size of deepwater discoveries being about three times those of shallow water. Core deepwater areas like Brazil, the Gulf of Mexico, and central West African basins are being supplemented by expansions in Australasia, North and East Africa and the North Sea, stretching geographical boundaries of deepwater activity and providing increased opportunities for oil field service companies. The application of new technology to aide our customers in the planning and execution of their deepwater development is critical for them in balancing their risk-reward matrix, and is an area of significant focus for Halliburton. For example, the Landmark suite of advanced 3D seismic interpretation and analysis tools are providing real value in West Africa and Brazil in helping customers gain an understanding of complex reservoirs, including subsalt. In the area of reservoir characterization, Halliburton’s GeoTap® IDS technology is allowing operators for the first time to capture and analyze reservoir fluids during the drilling process; while after drilling, during well testing, newly introduced DynaLinkTM technology offers analysis of reservoir flow potential, also in real time, reducing uncertainty and improving efficiency. Deepwater production represents roughly 6% to 7% of total world oil production today, and is expected to double in the next five years. Old field service companies that have the unique combination of technology, expertise, and infrastructure will participate meaningfully in the development of these reservoirs. We believe that Halliburton’s past and current investments are placing the company in an excellent position to benefit from the growth of deepwater activity worldwide. Dave?

Thanks, Tim. Let me now just quickly summarize where we’re at. Increase in overall activity and completion intensity in the Q2 have led to very high utilization rates and increased pricing for most of our product service lines in the US. Going forward we expect that the overall rig count will continue to grow but at a slower rate, and also we expect further pricing opportunities. Our already high utilization rate and growing cost threshold will serve to somewhat slow down the rate of improvement in our margins. Our international business showed progression in both revenue and margins during the Q2. We continue to believe that the second half of 2010 will be better for our international markets. However, we now expect that the growth will be more weighted toward the end of the year than we had originally anticipated. So we remain very bullish about the prospects of global deepwater activity and we will utilize our technology, capabilities, and global infrastructure to benefit also from this secular trend. Let’s go ahead and open it up for questions at this point.

Thank you. Ladies and gentlemen, (Operator instructions) One moment for the first question. Our first question comes from Dan Boyd of Goldman Sachs. Your question, please. Dan Boyd – Goldman Sachs: Alright, thanks. Good morning, guys. Can we understand that the progression of margin was throughout the quarter in North America, presumably the exit rate was much higher than what you reported?

Hi Dan, this is Mark. As I mentioned in my comments, the margins were actually fairly consistent in North America month to month. You know, we had seen in the first quarter a steady progression upward at quite a rapid pace; in the Q2 they leveled off quite a bit. And so the June margin itself wasn’t that far off of the quarter average.

Let me just add a little bit to that because it’s not that our ability to increase pricing slowed down. And I mentioned a couple times, we’re starting to have to deal a little bit with the affect of increasing costs. So we are attempting obviously to continue to raise pricing and raise margins, but our vendors are wanting a piece of that ability at this point in time. Dan Boyd – Goldman Sachs: Okay. And then as a follow-up: Latin America is the one area that also surprised us with margins coming in a little bit better than expected. Understanding that Mexico is going to pull back a little bit, but can you help us understand what sequentially drove the increase in Mexico? And have you started the cost, cutting costs there already? Tim Probert : Well, the big story in Latin America is Brazil, and Brazil is really what was the primary driver for the strength of Latin America during the quarter. With respect to Mexico, I think the best way to think about Mexico is that the current quarter sort of provided a peak of Mexico performance. And as Dave alluded to, we do not expect that to continue. Clearly the budgetary constraints are going to have a significant impact on that. Dan Boyd – Goldman Sachs: As you go to I guess right size your cost basis in Mexico and you potentially look to take a charge, excluding that charge, should we expect Latin American margins more or less flat from here?

I think that’s a good assumption. Dan Boyd – Goldman Sachs: Okay. Thanks, I’ll turn it over.

Our next question comes from Bill Herbert with Simmons & Company. Bill Herbert – Simmons & Company: Thanks, good morning. Dave, you mentioned that your international and especially your Eastern Hemisphere customer base was a little bit more reticent with regard to the pace of spending increases given the economic outlook. Is that reticence coming predominantly from IOCs or is it NOCs as well?

No, it’s primarily the IOCs and it’s really hard to tell what – there’s two things at play here. One is them sort of taking a look at the economic conditions and getting these big projects started, because on these major projects, once you start and sanction them there’s really no turning them off until you’ve spent a lot of money. So I suspect that a lot of our customers are using a pause from the Gulf of Mexico to sort of do a last study of their processes. It’s really a way for them to step back, take a couple of more deep breaths before they embark on some of these major, long-term projects. So we’re not concerned that these projects are not going to go forward. They will go forward, but I think that everyone’s like I said, just taking a last breath or two and maybe delaying by a quarter or a half a quarter the sanctioning of these projects. Bill Herbert – Simmons & Company: Right, and I get the fact that clients are more introspective with regard to deepwater well designs and processes, and that’s mostly IOCs. But the reticence with regard to the overall economic outlook, that’s IOCs as well.

That’s correct, and I would say actually it’s primarily IOCs. Bill Herbert – Simmons & Company: Okay, good. And then secondly, again focusing on the second half of this year, which Eastern Hemisphere markets do you think relative to the first half are going to show the most positive rate of change?

Well, the most obvious one will be the North Sea. The North Sea has really struggled through the first two quarters, and I think any help in that market can’t help but look better against sort of the first half performance. And Algeria has been another one that has been troublesome in the first part of the year. That’s a big business for us and for other service companies. And with the changeover in management and some of the delays in sanctioning projects, that’s been a country that has relatively underperformed our expectations in sort of half one, which we hope would get better in the second part of the year. Bill Herbert – Simmons & Company: Okay, and I will sneak one last one in here. Any comments with regard to Russia, how it’s performing, and outlook for the second half of this year relative to your expectations coming into the year?

I think we would say in general that Russia’s a little bit below our original expectations for the second half of the year. That obviously remains to be seen, Bill, but our sort of general sense at the present time is that it may not perform quite as strongly as we had originally intended, and that was sort of in the double digit growth range that we’d announced I think at the end of the year. Bill Herbert – Simmons & Company: Okay, thanks very much.

Our next question comes from David Anderson of J P Morgan. Your question please. David Anderson – J P Morgan: Thanks. Hey Dave, I just wanted to get back to you, you talked about some long-term contracts on the US land market. It’s pretty clear you’re trying to avoid the ’05-’06 repeat when too much capacity entered the market. But now obviously access to capital isn’t what it used to be, but I would just think that long-term contracts would seem to be the best way to offset any kind of capacity concerns. So I guess a two-part question: one, how concerned are you about capacity as of the next twelve months in the US land market; and second, what do you need to see in the long-term contracts to make it more attractive to you? Is it a function of locking up a prescribed utilization rate, is it index pricing? I’m just kind of curious about what it would take for you to take to enter into more of those.

Yeah, good question. I made the comment that I’m not yet convinced they’re the way to go for a couple of reasons. Especially they’re not the way to go for us where we are in the cycle right now because you’re essentially locking in essentially a fixed price for a set amount of utilization. And as I indicated, I believe that we have upside to prices in North America and I would not want to tie equipment down with a long-term contract and miss some of the pricing upside, while at the same time not being able to fix the cost side of the equation. The second is that although people get enamored or sometimes our people get enamored with sort of the recurring fixed price nature of these, our customers have shown no compunction to just tear the contract up when it’s to their advantage when pricing is going down. So I don’t see that we’re getting any downside price protection, and I believe we are limiting our upside return potential by entering into some sort of a long-term contract that’s got a fixed price component to it right now. The ones we are experimenting with have an element of a fixed price and a commitment as to percentage utilization, but again, those are very difficult to measure in practice and therefore we’re just going to stay away from them right now for the most part as I said, because I’m not convinced they yield us the highest overall return over a cycle. David Anderson – J P Morgan: That contract that you indicated last quarter, that $750 million contract to Wilson, does that qualify for that evaluation?

No, no it doesn’t. That was a different kind of contract. David Anderson – J P Morgan: Okay. On a different subject you were talking about reallocation costs occurring in the Gulf of Mexico. I guess two questions – how quickly can you get this done? Is that kind of by the end of the year? And also internally how many active rigs are you guys counting on the deepwater twelve months from today? I think the last I spoke to you guys, you were thinking about 17 rigs. That was a month and a half ago, and I can’t imagine things have gotten any better in your opinion.

Well, with respect to our planning what we told you last time is we were planning on about 50% of the level of activity, roughly 17 rigs, approximately six to 12 months after the suspension was lifted. There’s probably no reason to change that right now in terms of an assessment of what might take place. And you have to have a basis for planning your business – that’s the one that we’ve used, and we’ll obviously modify that based on the flow of information that we’ve received. But with respect to the movement of capital items, that happens relatively quickly and yes, that reallocation will be complete by the end of the year. David Anderson – J P Morgan: And if you took your offshore margins, you’re moving, obviously everybody else is moving as well. I think you highlighted that you’re not too sure margins are going to go. How concerned should we be about excess capacity? I didn't think there was a big capacity issue with a lot of the equipment internationally. Is that true?

You know, there is a limited amount of assets that are likely to be moved into the international markets for a variety of reasons – some of it is the type of equipment, some of it is size, some of it is suitability. So you know there’s always that potential that everyone doing everything at the same time may have an impact, but there's certainly no evidence that that’s taken place at the present.

Things like vessels for an example might be more impactful, if vessels move on a wholesale basis to other markets. David Anderson – J P Morgan: Okay, thank you.

Our next question comes from Scott Gruber with Sanford Bernstein. Please go ahead. Scott Gruber – Sanford Bernstein: Yes, good morning, gentlemen. I wanted to turn back to the guidance of the earnings impact and the drilling suspension in the Gulf. Do you assume any deepwater activity in those figures?

No. If you think about the 5% to 8% we announced, if a reasonable level of shelf drilling goes forward in the next couple of quarters, and I think that’s a little iffy at this point in time, then I think the hit to earrings will be at the low end. If the shelf continues to find it very difficult to get permits and therefore they can’t drill, then I think it’s going to be toward the upper end. One of the things we are not doing is we are not going to diminish our infrastructure in the Gulf of Mexico. So yes, we’re going to try to move people; yes, we’re going to try to move equipment. But we are going to maintain our vast Gulf of Mexico facilities - lab, manufacturing, all of those facilities – on the basis that the Gulf is going to come back, which we believe it will. And that will be part of a drag on earnings for a period of time. But in our view, when the Gulf comes up again you’re going to have to have that stuff in place. I’d just rather keep it and pay for it on an as-we-go basis than try to recalibrate it and reconstitute it at some point in time in the future. Scott Gruber – Sanford Bernstein: Just to be clear, the upper end of the range includes an anemic outlook on shallow water activity and virtually no deepwater activity?

Yeah, the 8% is anemic shallow water and the bottom of the range is a more robust shallow water environment. Scott Gruber – Sanford Brown: Got it.

It’s $0.05 to $0.08, of course.

Yeah, the lower of $0.05 and the higher of $0.08, yes.

I think it is interesting to note that we were mobilized last week on a shelf well construction project, so it’s not, it’s by no means a trend but it does sort of indicate that we’re starting to see some movement on the permitting front. Scott Gruber – Sanford Bernstein: Okay. And an unrelated follow-up: Can you provide some color on where you think the industry stands in the drill to hold acreage by production trend?

Of course, there is no sort of perfect repository of this information, but the general information that we have from our own organizations suggest that we saw a decline in Q1 in the overall position. And drill to hold, the inventory of wells that is out there increased somewhat in Q2, and we expect to see a sharp increase in Q3 based on the information that we have, particularly Bakken and Eagle Ford. So we’ll see that inventory continue to rise. With respect to drill and hold specifically, most of our customers really indicate to us they still have a firm amount of activity to take them through into 2011.

Yeah, and I think one other area that is sort of pushing drilling that a lot of people have not focused on is companies that are drilling with other people’s money. And keep in mind that over the last year a number of the big US gas players have announced transactions with primarily outside of the US IOCs and in some cases other money players to essentially have them carry their drilling programs for them. And I think that is actually going to also drive some additional drilling because you know, the customers have the liquidity provided by others to be able to do so. Scott Gruber – Sanford Bernstein: Okay, great.

Our next question comes from Kurt Hallead with RBC Capital. Kurt Hallead – RBC Capital: Hey, good morning. A quick follow-up here on once again that $0.05 to $0.08 impact in the third and fourth quarter. Is that, do you think the increase in your North American land related business will fully, partially, or more than offset that $0.05 to $0.08 impact from the Gulf of Mexico in the second half of the year? Better activity, better pricing on North American land – is that going to offset that $0.05 to $0.08 number?

Kurt, this is Mark. I think as we look forward in terms of what the US businesses are doing, in the Q3 it seems like US land will probably fully offset or at least get very close to fully offsetting the weakness in the Gulf. Fourth quarter, you know, as we move into winter stiffs in our business it may be a little less, but that’s, we’re still very excited about what’s happening on US land right now. Kurt Hallead – RBC Capital: Thanks. And then a question for Dave: In your discussions with your varying oil company customers, how do those customers handicap what the Gulf of Mexico could look like twelve months out? What kinds of rules and regulations are they preparing for and when do they think that they’re going to be able to start to ramp up their activity?

Well, I think the discussions are many and the conclusions are varied, I guess would be the best way to put it. I think that nobody believes that they will be out of business in the Gulf of Mexico let’s say a year from now. I think one of the big concerns is going to be the ability to get the deepwater rigs to come back into the Gulf of Mexico market if they’re absorbed in other parts of the world. Remember, these things take a long time to drag out of the Gulf and halfway around the world. That’s a lot of downtime on those rigs. So the concern is the ability to get the rigs, bring them back in here. What are the insurance costs going to be? What are the new regulations going to be? So I would say that in the next twelve months that there's probably very little discussion taking place about the ability to ramp up to anywhere near the level that we were at. But if you look at the prospects, you look at the reservoirs there, a number of the big IOCs are very heavily committed to the Gulf of Mexico and they certainly will start up as fast as is practical after they get the go-ahead. Kurt Hallead – RBC Capital: And last follow-up here: Your reference on pricing, I was wondering if you just- I think it would be fair to assume that pressure pumping has the best pricing dynamics at the moment. I was just wondering what product lines have the least ability to get pricing at this stage?

Well clearly our stimulation business leads the pack in terms of pricing. I think the important thing really to understand here from our standpoint is the way we try and use our stimulation business to provide an integrated package of value propositions for our customers. Probably as we look across the board, clearly stimulation is at the high end; directional drilling, drill bits, completions in the middle; and wire line probably is at the bottom end of the range in terms of pricing realization. Kurt Hallead – RBC Capital: But all product lines are gaining some element of pricing at this point. Is that true?

Correct. Kurt Hallead – RBC Capital: Okay. Thank you.

Our next question comes from Ole Slorer with Morgan Stanley. Ole Slorer – Morgan Stanley: Thank you. Mark, can you give us an update on CAPEX for the year?

Well, we’re still looking at approximately $2 billion, in that range, the $2 billion range for total CAPEX for the year. So still sort of in line with the previous guidance at this point. Ole Slorer – Morgan Stanley: Okay, and when you increased the previous guidance it was because you saw some international projects for 2011 move to 2010. It sounds like some of that is slipping a little bit again, so does that mean that you are tweaking your CAPEX more in favor of North American stimulation at the moment?

Well, I think yeah. Part of the increase the last time around was also an acceleration of some capital deliveries into the US market where we saw demand for things like pressure pumping equipment increasing. So that was serving to offset that, and I think that continues to be the case – any kind of a weakness that we might see in capital deliveries in international will be offset by deliveries for additional capacity in the US land. Ole Slorer – Morgan Stanley: Okay, thank you. Second question to you: This has always been to me somewhat a bizarre relationship to psychology around international pricing relative to what’s going on in the North American market, and clearly the North American market is divided between the very hot land market and the not-so-hot deepwater offshore markets. What are you seeing in terms of the psychological impact on overseas markets based on what’s going on in the US at the moment?

Clearly international pricing is still very competitive, Ole. We have, as you recall we had a very active 2009 in terms of bidding processes as our customers took advantage of the changing dynamics in the industry, and those contracts clearly have come into play during the course of 2010. And as you would appreciate there is some time between the ability to move those prices and the start up of those contracts. So I would say in general international pricing is still quite challenging. There are a few areas that are a little brighter than others, but in general, that psychology if you like from the North American market is still prevailing in the international markets. Ole Slorer – Morgan Stanley: Okay, Tim, that sounds very similar to what you said last quarter, and yet you increased Middle East margins by 300 basis points and the rest of the Eastern Hemisphere by 100 basis points sequentially. So is there a volume effect here? I don’t know what’s going on.

No. I think, Ole, that one of the things, once you get a handle on what your pricing dynamics are in Eastern Hemisphere markets, because of the longer-term nature of those contracts, it’s easier to get your cost structure in line to support those contracts at what is a sufficient margin to take them on. And as Tim said, in 2009 we were really dealing with a rapidly changing pricing environment. We really didn’t have an idea where that was going to settle down, and therefore we did not do a lot of changing to our cost structure last year. Now that we know what these contracts are, what we’ve won, what the pricing is on them, we can make sure that our organization by country, by product line, is now aligned with supporting that contract but also being able to give us a chance to increase our margins going forward. Ole Sorer – Morgan Stanley: So you see continued improvements to right size your infrastructure, your cost structure relative to the business that you’ve signed?

Oh yes. Every quarter that’s something that we work on and we try to focus on and sharpen up our operating capabilities by country at a lower cost. Ole Sorer – Morgan Stanley: Okay, finally just one more on Iraq. There’s been a whole bunch of announcements over the past 24 hours whether it’s Lukoil or BP, and there’s some very large headline numbers. Is it 2010, 2011, or 2012, or when should we expect that this will be a meaningful contributor for you?

I don’t think you should expect to see anything in 2010. We're in the back half of the year now. You see a lot of headline numbers; I saw the same ones you did. We’re having the same discussions with a lot of these customers. It’ll take awhile to get these contracts awarded. Typically then they don’t have startups for three to six months after award. So I would say that you’ll see awards in 2010, probably costs and ramp up in 2011 with some commensurate revenues, and then sort of a more reasonable operating environment probably into 2012. Ole Sorer – Morgan Stanley: Okay, thank you very much.

Our next question comes from Angie Sedita with UBS. Please go ahead. Angie Sedita – UBS: Great. Well first, congratulations on a very good quarter.

Thanks.

Thanks, Angie. Angie Sedita – UBS: The first question, talking about pressure pumping which we have at length already, but do you have any concerns – you said you were going to protect market share. Any concerns so far in what you’re seeing from your peers as far as new capacity additions? And then coupled with that, one of your peers obviously with the recent merger and then your other peer with a renewed focus on North America, are you seeing any change in their behavior specifically?

Yeah. I think at this point in time everybody appears to be acting pretty responsibly. And we did work hard to increase our market share in the last downturn and we believe we have; that market share is ours to keep, and we’re going to bring the equipment in necessary to support it. We don’t see anything happening right now which would let us conclude that there’s a big wave of equipment coming into the North America market other than what an individual company believes is necessary to support its own market share. Angie Sedita – UBS: Okay, good to know. And then another is a follow-up to Bill’s question earlier in the call. He asked about where you expect to see stronger growth internationally. What markets outside of Mexico and Venezuela could see a slower recovery on the back half of the year?

Which markets could be slower? You’ve already touched on Mexico. I think that you know, clearly North Africa, particularly Algeria as Dave mentioned earlier is somewhat of a concern, primarily because we see some, shall we say, slowness in decision making there causing some hold up in overall activity. West Africa in general, there has been a little bit of a slowness there in terms of the mobilization of new contracts which we had expected to take place by now, though the full force of those I think will come in during late 2010. Other than that, Angie, I don’t have any specifics, other than of course the North Sea continues to be a challenging chestnut here. Activity has been quite slow in the first half of the year. We have better expectations for the second half, but we’ve said that before. Angie Sedita – UBS: Okay. And then finally just as a follow-up to that, do you think there’s any risk to a push out to the international recovery to 2011 given global economic conditions, the Gulf of Mexico, a little bit of nerves [ph] by the IOCs? Or do you think clearly the NOCs should begin to pick up in Q4 and we’ll see at least some of it this year?

Yeah, every indication we have at the present time is as Dave said in his comments, that we’ll see a slightly slower rate of change in Q3 than we had originally expected, picking up momentum in Q4. Angie Sedita – UBS: All right.

Our next question comes from Jim Crandell with Barclays. Please go ahead. Jim Crandell – Barclays: Good morning. Dave, last cycle in US pressure pumping there was shortages of equipment, competitors built capacity and you and your main competitor lost considerable market share. And I think you said “We will not let that happen again.” You seem to me more restrained on prices and seem to be planning to be more aggressive in adding equipment early on than you were last cycle. Am I assessing things correctly?

I think, Jim, one of the lessons we learned from the last time is that you can push pricing up so hard so fast across all basins that you make it uneconomic for your customers to continue to drill; and once that cycle sort of turns over it can get pretty ugly as we’ve seen. So as I indicated in my comments, we’re trying to go basin by basin this time, work with our customers on understanding the returns they need and helping them understand the returns we need. And the returns we need sometimes are more about efficiency than they are about pricing. So we’re trying to do more of a rifle shot approach instead of a shotgun blast in the market. And we have a targeted market share that we have right now and we are going to build equipment to meet that targeted market share, but we’re not going to build any equipment beyond being able to do that. And I hope everybody else is sort of equally responsible. Jim Crandell – Barclays: And on that last point you made, David, what do you see on that score today? David Lesar : I see everybody being pretty responsible right now. Jim Crandell – Barclays: Okay. My second question is exclusive of Iraq, how active do you see bidding on IPMs in the second half and over the rest of the year? And specifically where might that bidding activity occur?

The IPM market right now, if you look at the markets that were embracing IPM in a big way obviously were Iraq, a little bit of Saudi Arabia - you know we won the South Ghawar project which by the way is going very, very well - and Algeria. And of course Mexico is the story everybody knows about. Obviously the IPM day seems to be coming to an end in Mexico. Algeria, it’s still a market that there’s a lot of IPM activity in but we have been unsuccessful, as has our competitors in getting extensions signed by Sonatrach on a lot of the existing ones. So that’s out there as a market but right now it’s pretty slow in Algeria. Iraq obviously will be a big IPM market, but you see scatterings of it here and there but it doesn’t seem to be developing a big bow wave out in front of it right now. And I think that as commodity prices have stabilized, especially liquid commodity prices, I think you’re seeing more and more of sort of the standard type of contracts more than a reach for an IPM type of engagement. Jim Crandell – Barclays: Okay. And lastly, Dave, on Iraq, what would you, do you think that all 11 or 12 sanctioned projects by the major oil companies will in fact be awarded this year? We’ve seen announcements as was alluded to on West Kerna and Majnoon and Zubair. But do you think that other companies like Petronas and Gazprom, do you think that all 12 will go forward with contract awards?

I don’t think that all 12 will get done this year for a couple of reasons. One, the service industry’s capacity to handle - all that is going to be stretched with just some of the major initial big ones. Number two, I think our customers are finding it maybe more difficult than anticipated to get a tender award through the National Oil Company approval process, which all of them are required to do in Iraq. And therefore, you will see the major ones awarded this year but you definitely will not see them all. Jim Crandell – Barclays: And would you expect to see, Dave, bidding for the first one (inaudible) wasn’t so hot. Do you think the bidding will be reflective of the fact that capacity is going to be tight as we get into the second half of the year and we hopefully will see better pricing and margins on future contracts there?

I hope so. Jim Crandell – Barclays: Me too. Thank you.

We’ll take one more caller.

Our final question comes from Stephen Gengaro with Jefferies. Stephen Gengaro – Jefferies: Thank you. Good morning, gentlemen. Just a quick sort of follow-up on North America if you don’t mind. Over the last six months we’ve certainly been surprised by the pace of your utilization increases. Can you sort of highlight, if you will, the areas where that has been maybe the strongest and the biggest surprise to you? And then second, when you look at the market now, do you feel like the benefits of being big in North America are improving because of that versus a couple of years ago?

I mean certainly the benefits of being big, we believe in it. And when we say “big,” I mean have the ability to bring multiple product lines to a customer offering, and have one poke through to the other. So I think being integrated and having multiple product lines certainly is working to our advantage. You know, if you look at why the sort of sudden increase in capacity – one, we have been talking for a number of quarters about the higher horse powers that are needed to frac these shale plays, and we now have to show up on a major shale play with 40,000 horsepower just to sort of ante into the game. And if you look at the average horsepower per job all the way across the US, it’s doubled in the last six to twelve months. So not every job takes 40,000 horsepower, but the average job in North America has doubled its horsepower utilization. So that in itself is absorbing a lot of the industry capacity. The more aggressive horizontal drilling, especially in some of the hard to drill hotter shale plays, are eating drilling tools up. The higher horsepower, higher flow rates on the fraccing is eating frac equipment up, it’s eating drill bits up. And so the nature of the drilling, the more difficult type of situations, and the higher horsepower needs all are increasing the demand for what you have to show up with on the job, and it’s also consuming that equipment a lot more quickly. That in itself, as we have said in prior quarters, we thought would help balance out the supply and demand of equipment in the US. And I think that’s turned out to be a dead-on call. Stephen Gengaro – Jefferies: And that phenomena is obviously pretty sticky versus normal cyclical dips and peaks.

No, that’s correct. Stephan Gengaro – Jefferies: Thank you.

All right. Before we close we would like to announce that Halliburton’s Q3 2010 Conference Call will be held on Monday, October 18th, 2010 at 9:00 AM Eastern Time. Thank you for participating on today’s call. Shawn?

Thank you ladies and gentlemen. Thank you for your participation in today’s conference. This does conclude the conference. Everyone may now disconnect. Good day.