Baker Hughes Company (BKR) Q3 2011 Earnings Report, Transcript and Summary

Good morning. My name is Brandy, and I will be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Third Quarter 2011 Earnings Conference Call. [Operator Instructions] I would now turn the conference over to Mr. Adam Anderson, Vice President of Investor Relations. Sir, you may proceed.

Thank you, Brandy. Good morning, everyone. Welcome to the Baker Hughes Third Quarter 2011 Earnings Conference Call. Here with me today are Chad Deaton, Baker Hughes Chief Executive Officer and Chairman; Martin Craighead, President and Chief Operating Officer; and Peter Ragauss, Senior Vice President and Chief Financial Officer. Following management's comments, we will open the lines for your questions. Reconciliation of operating profits and non-GAAP measures to GAAP results for historic period can be found on our website at www.bakerhughes.com in the Investor Relations section under Financial Information. Finally, I must caution you that any company outlooks discussed this morning are subject to various risk factors. We'll try to highlight these risk factors as we make these forward-looking statements. However, the format of the call prevents a more thorough discussion of these risk factors. For a full discussion of these risk factors, please refer to our annual 10-K/A, 10-Q and, in particular, the forward-looking disclosure in this morning's news release. With that, I'll conclude our discussion of the administrative details and turn the call over to Peter Ragauss. Peter?

Thank you, Adam, good morning. This morning, we reported adjusted net income of $518 million or $1.18 per share. This excludes the noncash tax benefit of $214 million associated with the reorganization of certain foreign subsidiaries related to the BJ Services integration. You will see a corresponding decrease in the deferred tax liability on the balance sheet. This adjusted net income also excludes a loss of $26 million related to the early extinguishment of our $500 million notes that were due in 2013. On a GAAP basis, net income attributable to Baker Hughes for the third quarter was $706 million or $1.61 per diluted share. Revenue was a record $5.18 million, up 27% or $1.1 billion from last year and up 9% or $437 million sequentially. Adjusted EBITDA was $1.15 billion, up 62% from last year and up 13% sequentially. To help in your understanding of the moving pieces, I'll bridge Q3 last year EPS to this quarter's EPS. GAAP EPS a year ago was $0.59 per share; subtract $0.06 for the early extinguishment of debt this quarter; add $0.49 for the noncash tax benefit from the tax reorganization; subtract $0.07 for higher corporate costs, net interest expense, income taxes and a higher share count. Operations added $0.66. That brings us to $1.61 per share on a GAAP basis. Bridging the sequential quarters, GAAP EPS for the last quarter was $0.77 per share. First, add back the $0.16 impact of the Libya reserve to our Q2 2011 results; subtract again $0.06 for the early extinguishment of debt this quarter; add again $0.49 for the noncash tax benefit from the tax reorganization; subtract $0.04 for higher corporate costs, net interest expense and a higher share count. Corporate costs were $15 million sequentially, primarily as a result of the planned SAP implementation, the pressure pumping product line in North America. Operations added $0.23 per share. Lastly, we benefited $0.06 per share from a more favorable tax rate this quarter. That brings us to $1.61 per share on a GAAP basis. Table 4 of our earnings release, we provide financial information excluding the impact of the $70 million Libya charge in the Q2 results to provide more meaningful comparisons between quarters. From this point on in the conference call, any comments on revenue, operating profit and operating profit margin refer explicitly to Table 4. Revenue in North America was $2.72 billion, up 35% compared to a year ago and up 15% sequentially. North America operating profits were $607 million, up $267 million year-over-year and up $167 million sequentially. North America margins were 22%, up 540 basis points from a year ago and up 377 basis points compared to the last quarter. Q3 2011 has benefited from the seasonal recovery in Canada. The rig count was slower to ramp up compared to prior years due to the unusually wet weather, really through the whole spring. It picked up pace through August and averaged 441 rigs for the quarter, 22% higher than the same quarter last year. Activity in the U.S. continued to increase with the average rig count up 20%, compared to the same quarter last year and up 7% sequentially. Moving to the international side. International revenue was $2.13 billion, up 19% compared to a year ago and up 4% compared to the prior quarter. Operating profits were $260 million, up $165 million year-on-year and down $16 million from the prior quarter. International margins were 12.2%, up 693 basis points year-over-year and down 124 basis points sequentially. As provided in earlier guidance, we still expect to exit the year with international margins around 15%. Our Industrial Services and Other segment, revenue was $336 million, up 21% compared to last year and up 4% compared to last quarter. Operating profit was $28 million, down $8 million compared to a year ago and down $6 million sequentially. Operating margin was 8.2%, down 216 basis points from last quarter. This was primarily driven by an increase in cost of goods sold. We expect Q4 margins to be in line with Q3 for the industrial and other segment. Turning to the balance sheet, at quarter end, our total debt was $3.9 billion, up $292 million from the prior quarter, reflecting the issuance of $750 million and 3.2% 10-year notes and a redemption of $500 million of 6.5% notes. These 3.2% notes have the lowest 10-year yield ever issued by any company in our industry. Our total debt to capital ratio was 20%. Accounts receivable grew some $540 million in the quarter, and this increase was driven by revenue growth, as well as the usual invoicing delays resulting from the implementation of SAP for our North American pressure pumping business. We expect our accounts receivable to return to more normal levels in line with our business growth in Q4. Our capital expenditures were $628 million this quarter, bringing the year-to-date total to $1.65 billion. At the end of the quarter, we had $803 million in cash and short-term investments. During the quarter, we replaced our $1.7 billion credit facilities with a new $2.5 billion 5-year facility. This new facility has no financial covenants, which is another reflection of the strength of our balance sheet. Finally, I'll provide you with our updated outlook for the fourth quarter of 2011. An interest expense to be between $55 million and $60 million; corporate costs, between $75 million and $80 million; depreciation and amortization expense, between $340 million and $350 million. CapEx for the quarter will be about $700 million to $750 million resulting in a full year capital spend of between $2.3 billion and $2.4 billion. Our tax rate is expected to be between 32% and 33% for the fourth quarter. I'll now turn the call over to Martin.

Thanks, Peter, and good morning, everyone. This was a record revenue quarter for Baker Hughes, provides further confirmation that our transformation to a geomarket structure is paying dividends. Overall, we're pleased with the results and the growth of our major businesses. We still have some challenges and efficiencies to work through with the goal of further improving our overall margins next year to better reflect the value that our products and services provide the industry. I'd like to start out by providing our listeners with an update on pricing. Large international contract renewals continue to remain highly competitive. But when you put those contracts aside, prices are increasing, albeit slowly. It is our expectation that if commodity prices remain where they are and North America activity stays where it is, international pricing will continue to trend higher. As for pricing in North America, while there are certainly variations across our product lines, on the whole, we're still able to modestly grow pricing in excess of cost increases. In U.S. land, we track the pricing on 8 of our product lines across 7 principal basins. And with regards to pressure pumping, for example, in Q3 relative to Q2, 2 basins had pricing trending down, 2 basins had pricing trending up and 3 basins were unchanged. And we believe these trends will remain the same into Q4. As I mentioned, however, each product line is experiencing unique pricing behaviors. Before we move up pricing, I'd like to be clear that my commentary for both international and North America pertains only to price improvement on like-for-like services. Given the increasing reservoir, operational and regulatory challenges our industry faces, we will continue to high-grade the product and services mix, which, in turn, leads to comparably higher prices. Now I'd like to discuss operating results, and I'll start with North America. In Canada, unconventionals continue to drive our activity. While rig count was up 23% year-on-year, well count increased about 15%, highlighting the greater complexity of the Canadian well construction market and therefore, the greater service intensity per well drilled. Significant element of our Canadian unconventionals are the oil sand developments. Baker Hughes has an enviable position in production chemicals and ultra-high-temperature ESPs in this growing market. Strong rig count growth we saw during the latter part of Q3 in Canada is very encouraging, but overall shortages of people, equipment and consumables will temper growth over the next few quarters. Moving to the Gulf of Mexico, we saw gradual activity improvement sequentially, driven by an improvement in the permitting process for Deepwater wells. While margins are improving, they're still significantly below the pre-Macondo levels due to less exploration and high-end development activity and the higher operating costs associated with increased compliance requirements. As we've highlighted on previous calls, Baker Hughes remains bullish on the Gulf of Mexico and we're very well positioned to support our customers as the activity and mix eventually resume to historic levels. Turning to U.S. land, clearly, the unconventional shale plays continue to be the big story. Even with the fairly significant volatility in the commodities and equities market, we haven't seen our customers alter their spending behavior in any material way, and the proof of this is in the 6.5% sequential growth in the U.S. rig count. Demand continues to outstrip supply across most of our services, especially drilling services, completion systems, pressure pumping and wireline. We're adding capacity to our supply chain at record rates across all product lines to meet our customers' demands. But furthermore, like the industry, we continue to be challenged by shortages of water and sand and we're working diligently to resolve the supply chain and logistical constraints. Staffing continues to be another challenge for the industry. Baker Hughes has already created thousands of new jobs in the U.S. and Canada this year, and we're working hard to hire an additional 6,000 people over the next few months. We completed the first OptiPort frac job in the U.S. this quarter. This particular horizontal well in the Barnett was successfully completed with 49 stages. The OptiPort multistage fracturing system, as we highlighted at the Analyst Meeting earlier this year, saves time and money by eliminating rig up and rig downtime between stages, enables more efficient fluid use and most impressively, essentially allows for an unlimited number of stages. Last quarter, we reported on some of our newest technology such as of the next generation Frac-Point, In-Tallic, the IN-Tallic disintegrating frac balls and the AutoTrak Curve. And we're very pleased to report that these continue to experience tremendous customer demand. As we work to ramp up supply of these new products, we're quite optimistic that these, as well as others in the pipeline will have a meaningful impact in helping customers even more efficiently develop their substantial unconventional resources. Initially, all of these new technologies are being introduced in North America. But over time, they will be equally applicable across the international unconventional markets as well. What's becoming increasingly apparent with these unconventionals is the technology and intellectual challenges to unlock, if you will, the code of optimal field development. To meet these challenges, we've co-located integrated teams comprised of reservoir engineers, geoscientists, completion specialists and drilling engineering experts to partner with our customers to work through and resolve these challenges. This is further evidence of the changing relationship between customers and oilfield service providers in North America. And finally, the continuing shift to oil-focused drilling in North America benefits Baker Hughes' production-related businesses. Oil wells require artificial lift, they require more chemicals and in general, they require more work over services compared to natural gas wells. Evidence of this trend is in an award we received this quarter for 360 well ESP contract in the Mid-Con region, driven largely by our reputation for superior reliability and longer run times of our ESPs. Internationally, revenue grew 4% sequentially. And during the quarter, margins contracted as a result of an unfavorable product mix. In Europe, revenue was up slightly, but margins deteriorated. This was primarily due to product line mix, coupled with lower drilling activity in Norway and other transitory costs. In the U.K., activity levels were flat as operators considered divestures and the impact of potential tax reforms. In Poland, we are positioning ourselves to take advantage of future growth in the unconventional businesses where we recently performed a horizontal tight gas frac. We expect Europe to return to normal margins in the fourth quarter. Moving from Europe to Africa, starting with Libya. The outlook there has significantly changed, and we're hearing from our customers that they hope to get back to work as soon as it's safe to do so. We've done an initial assessment of the status of our facilities, but at this time, it's a bit premature to speculate when operations will return to normal. We'd like to acknowledge the dedication and commitment of our local employees during this difficult period. We wish them and their families the very best through the next stage of Libya's transition. In Algeria, operations improved modestly, but a shortage of consumables severely constrained our stimulation activity during the quarter. We expect this to return to normal during the fourth quarter. We were awarded a 3-year contract to provide drilling services on over 70 wells in Algeria. This contract offers another data point to the effectiveness of the geomarket structure. In Russia, there was moderate improvement in activity and we were awarded an important contract to provide completions, artificial lift and chemicals on an offshore Arctic project. Moving to the Middle East and Asia Pacific region, sequential activity remained largely unchanged. In Asia Pac, we drilled sidetracks in 4 different wells using our advanced coiled-tubing drilling systems. This technology enabled operators to efficiently sidetrack an existing well to a new reservoir location without a full rig, while providing superior well productivity results compared to conventional techniques. During the quarter, we installed the region's first GeoFORM screen. We were able to significantly reduce the complexity associated with performing a conventional sand control job in a very remote environment. In the Middle East, we did not see the substantial increase in rig activities some had expected, but we believe the region's national oil companies will execute on their plans to grow the rig count. Significant awards in wireline and directional drilling as well as our continued success in completions, artificial lift and chemicals demonstrates the execution performance of our geomarket leadership there. As we announced a few weeks ago, we were awarded our first integrated drilling project in Iraq for LUKOIL. This project consists of drilling and completing a total of 23 wells and serves as an important benchmark for us in Iraq. We're gearing up now and we expect the first rigs to begin operations early in the first quarter. Further, we've been awarded an important multi-service project -- the Khafji joint operating company. This work, which is in the neutral zone between Saudi Arabia and Kuwait, includes an integrated suite of products and services on 3 drilling rigs. In Latin America, we continue to see sequential revenue growth. As in the other regions, the theme continues to be about the application of technology and how it's solving our customers' problems and enabling them to develop their newer resources. In Brazil, this quarter, we continue to strengthen our position as a leader in drilling services in the presalt and we were awarded a new multi-well drilling optimization project. In October, we opened the Baker Hughes technology center in Rio, and this is our 10th technology facility worldwide. This new center will further elevate the commercial relationships we have with the Brazilian customer community by establishing higher levels of intellectual partnership as we collaborate to solve some of the toughest drilling and production challenges. In Mexico, the lab projects and growth in the offshore market are encouraging. In particular, the Corelio [ph] field laboratory has been successful for Baker Hughes, and we have been able to leverage our technology and reservoir expertise to impressively grow production in our assigned area. In Argentina, we continue to position ourselves to take advantage of the unconventional developments. Our view is that this is one of the most attractive near- to medium-term opportunities for international shales. So in closing, our North America business delivered, and we believe the opportunities in this market will continue to be strong going forward. We also believe that Baker Hughes is very well positioned to capture an increasing proportion of the market. We're pleased with our international revenue progression, but our margins were challenged this quarter. We're addressing these issues, and we're confident we'll deliver on our fourth quarter margin goal. At this point, I'd like to turn the call over to Chad.

All right. Thank you very much, Martin. Good morning, everyone. Overall, I have to say I'm pleased with the results of this quarter. Our global revenue growth was up 9% sequentially, and the change in sequential operating income was 20% -- 21%, and both categories are near the top of our peer group. Our international margin deterioration was mainly attributable to Europe and, as Martin discussed, we've addressed those issues and they'll return to more normal levels in Q4. As I did on the last call, I'd like to give you an update on our progress toward the goals we laid out in our Investor Meeting earlier this year. Our overall improvement in international margins over the last 5 quarters has been substantial and we are nearly 700 basis points better than we were at this time last year. We maintain our expectations that we'll meet our 15% international margin goal upon exiting 2011. In order to achieve this 15% exit goal, as we've seen in previous 4 quarters, our supply chain will be challenged to meet a record backlog of product deliveries. Second, we are strengthening our presence in the offshore markets as evidenced this quarter by the inaugural deployment of the Blue Tarpon stimulation vessel. We now possess the 2 most capable stimulation vessels in the Gulf of Mexico, enabling us to service the deeper, complex reservoirs of the deep Miocene and lower tertiary formations. The third area, we maintain our view that we can sustain leading margins throughout the cycle in North America. We had a strong 370 basis point improvement in North America margins from Q2 to Q3. And as the Gulf of Mexico returns to our expected share mix, we will see additional improvement. Our balanced product portfolio and strong production-related services give us the ability to navigate any potential short-term market weakness while preparing our company for the long-term growth. Fourth, we continue to position our supply chain organization to be a leading strength and fundamental differentiator for us in this market. As I mentioned, we've seen a record order book for our completion tools driven by increasing demand for our high-end completion systems. We continue to open new manufacturing centers in key markets around the world. Last month, we broke ground on a new manufacturing facility in Malaysia. The plant will manufacture production-related equipment for our customers in the Asia Pacific region and will open in 2012. Just as we've told you consistently this year, we are firmly committed to operating responsibly and with the highest quality personnel in any oilfield service company. We believe that our industry-leading competency assurance program is vital to developing this capability. This program will service to both meet the -- serve us to meet both the evolving global regulatory requirements as well as to differentiate our people around the world when delivering services to our customers. And finally, we maintain our long-term objective to become the #2 pressure pumping player globally. To achieve this, we'll need to continue to grow our presence in the North America market, but also look for opportunities to grow our international footprint. The recent award of a multi-year, multimillion stimulation contract in the North Sea is an example of our commitment to grow this business. Let me switch topics now and give you a brief outlook on market conditions. Looking at the Baker Hughes rig count for Q4, we expect the U.S. count to grow by 5% sequentially to an average of 2,030 rigs. Canadian rig count should grow an estimated 9% sequentially to 485 rigs in Q4, and that compares to 441 in Q3. International activity will see a modest ramp-up and should average approximately 1,215 rigs in the fourth quarter, which is a 4% sequential improvement. Looking ahead to 2012, there's a lot of debate out there right now about the uncertainty in the market, but I'd like to take a minute and tell you how we're thinking about this. Many people have tried to draw a parallel between what is happening today and the end of 2008. And although there are reasons to be cautious, we think there are also very important differences. First, the North America market in 2008 was still predominantly natural gas driven, and only 20% of the rigs were targeting oil. As you all well know, the natural gas is strictly tied to the North American energy market and as result, suffered a decline from over $14 per Mcf to less than $3 per Mcf on a spot basis during the 2008 collapse. Today, over 50% of the rigs running in the U.S. are oil directed versus the 20% levels in '08, and a large chunk of those so-called gas rigs are in fact targeting liquids-rich reservoirs. Additionally, the business is far more technologically complex as evidenced by the increase in horizontal wells, which now represent nearly 60% of the U.S. rig count. This increase in complexity favors Baker Hughes technology rigs product offerings. In 2008, there was a substantial liquidity crisis that constrained our customers' ability to raise capital. Today, we aren't seeing that same level of capital constraint. Further, the IOCs and NOCs will continue to look for opportunities to expand their presence in North America through either JVs or acquisitions. In the international markets, project economics are naturally tied to Brent and appear to be very attractive at current commodity prices. Further, many operators have committed to increase their production capacity and must drill to not only grow their production, but also replace underlying declines. The duration of these projects is longer term by nature such as offshore, deepwater, remote locations and as such they're planned years in advance. Finally, the shift in activity to NOCs is demanding a higher level involvement and integration with the major oilfield service companies. Today, we are much better positioned through our infrastructure build-out, our reservoir consulting capability, the BJ acquisition and, of course, our geomarket organization to respond to this shift in the market. As unconventional resources decline increasingly in the world, we return to Deepwater, to shale and other difficult access reservoirs in order to extract resources to meet the world's energy demand. So let me wrap this up. As all of you know, effective January 1, Martin's going to take over the role of CEO and I'll remain as Chairman, so this will be my last quarterly earnings call. I want to take just a minute and thank all of you for all of your support over these last 7 years. Being CEO of Baker Hughes is not only been extremely satisfying, but it's been a privilege as well. This is a great company, it's full of great people and it continues to get stronger every day. We've made a lot of changes over these last several years. We've had some successes and, obviously, we've been faced with a few challenges. But we're in a much better position today to capitalize on this next up cycle than ever before. To our shareholders, I want to assure you that we have the right management team going forward. And for our employees that may be listening on this call, I want to thank all of you for your support and, obviously, for your dedication over these last several years. With that, Adam, let's open it up for questions.

Thank you, Chad. At this point, I'll ask Brandy to open the lines for your questions. [Operator Instructions] Brandy, could we have the first question please.

Your first question comes from the line of Bill Herbert with Simmons & company. William A. Herbert - Simmons & Company International, Research Division: Martin and Peter, with regard to the international margin bridge for the fourth quarter, historically, you guys have had very strong year-end product sales. I think last year, that probably accounted for close to half of your significant EBIT improvement in the fourth quarter. Is that pretty much the roadmap for this year's improvement as well from 12.2% to call it in the vicinity of 15%? Are year-end product sales expected to play a prominent role?

Absolutely, the product sales play a prominent role, but maybe a little bit unlike, say, some of the previous Q3 to Q4 walk [ph] bills. As we've said in our commentary, we had some transitory cost issues we are challenged with across all the regions. We expect those to abate. And we had some product line mix issues as well on the revenue side that didn't. Weren't as accretive as maybe some of the higher ends. So those 2 are a little bit more unique to this quarter. But yes, absolutely, Q3 to Q4 is a big part of a manufacturing company like Baker Hughes' year-end numbers.

Yes, Bill, this is Peter. Just to maybe put a bigger picture around it, we are expecting activity to increase in Q4 so that's beyond just the regular product shipments, right? And you've got what's typically, I guess, for Baker, unique to Baker is product shipments of completions equipment that we've talked about and also artificial lift that typically happened in Q4. Probably the reversal of some of the transitory costs, we had a little bit of severance, we had a little bit of ForEx like many of the others, we had some repair and maintenance costs a little bit higher in the quarter. And then we expect a favorable contract hopefully to pay out a little bit in the Q4 as well. So there's a list of 6 or 7 things, and I think I gave them to you in the order of magnitude that should bring us to the international margin number. William A. Herbert - Simmons & Company International, Research Division: Great. And then Martin, very quickly, you mentioned international pricing ex-big project starting to improve. Are we talking net pricing or gross pricing?

No, I think net pricing, Bill. William A. Herbert - Simmons & Company International, Research Division: Okay, good. And then lastly, with regard to North America, you mentioned constraints in the form of water, sand and people. Yet on the other hand, you've got accelerated frac deliveries at least I think as of the second quarter call, you did your -- in excess of the 40,000-horsepower for every 6 weeks that you were in the first half. I think the last time you talked about this, you were expected to win a disproportionate share of the Gulf of Mexico Deepwater rig reactivations in the fourth quarter. Revenue per rig in the fourth quarter thus in North America should still be pretty good?

Yes. And your comment on the -- you're right in the conclusion of accelerated deliveries in the fourth quarter for horsepower. But there's no getting around the fact that the logistical issues around sand, particularly, is challenging the efficiency of these new fleets. And it's just something we have to work through and get a bit better at managing. William A. Herbert - Simmons & Company International, Research Division: Okay. And lastly, Chad, I'm not sure if this is your last call, it sounded like it, but if it is, we've really enjoyed working with you. You've been really one of the true gentlemen in this business. So all of the best.

Thanks a lot, Bill.

Your next question comes from the line of James West with Barclays Capital.

Chad, let me echo Bill's comments, thanks for all your years of leadership and thoughts on the industry.

Appreciate it. Thank you.

Martin or Peter, you talked about a little bit of the kind of issues internationally that you were addressing or addressed. I guess I wanted to clarify the kind of cost issues you have particularly, as it respects to Europe. Have those been addressed right now, or is this still an ongoing process?

Yes, most of those are one-off unique to the quarter. I mean we took most of our -- we did most of our cost-cutting, as you recall, in the last half of last year with hundreds of hits that came out of the underperforming geomarkets and if you recall, we've taken a lot of overhead costs out. I think that the issue in Q3 were unique costs on, like I said, FX, a little severance, a little bit of maintenance that were unexpected and they're not underlying structural issues.

Okay. And then so do we -- if we take all those out from 3Q, then we think about 4Q, do you have to have a very strong product sales period to get to that 15% margin target? Or is that just giving you some cushion?

We still need those deliveries. I mean with the orders -- we got the orders in hand, now it's a question of just getting the products delivered to bring us up -- it is -- we still got to make up 280 basis points, and it's not all cost. It is activity and product shipments as well.

James, this is Chad. I think Peter hit it right on the head, and it's a very important point. It's not that we're hoping to sell these products in Q4. These products have been sold. Now it's the delivery, getting them out in the next couple of months -- not that we're hoping for the sale.

Okay, okay, fair enough. And then as we look about into international for 2012, at this point, you have assumed you have a vast majority of your revenue contract. And how are you guys thinking about international E&P spending growth for next year?

Well, as you say, James, I mean we're -- this is Martin. We're in the process of pulling all together and having this -- the conversations with our customers. And they themselves are still going through the process. But I got to tell you, there's not a customer on the international front, IOC, European independent or NOC that is anything but bullish on 2012 in terms of what their spending is going to be in response to trying to get their production up. And I think you've seen some of the challenges some of our customers have on the international front with regards to production and reserve replacement ratios and so forth. So we expect 2012 to be a better year in terms of activity, distinctly better than 2011.

Yes, let me throw something in because I just got back last night from SPE's only annual technical conference in Denver and I chaired a panel with actually a lot of our key senior customers were on there, Petrobras, Petronash, Shell, several others. And to a person not one of them talked about any type of slowdown in 2012. They're still very optimistic at very senior levels, so we're thinking 2012 still looks very strong.

Your next question comes from the line of Angie Sedita with UBS.

Martin, you mentioned in your comments about current pricing outlook in pressure pumping across some of the regions with some of the markets flat, down and up. Could you give us further details on what markets or where as far as up, down and flat? And how much are you seeing in pricing pressures so far, is it marginal or greater than that and then thoughts on 2012 pricing.

Okay. Angie, I've got a chart in front of me here and it's obviously, if you will, a bit of intellectual property, I'm not -- I can't share all of the ins and outs of it. We spend a lot of time trying to understand what's going on by product line and by basin. But I wanted to tease out pressure pumping because it's obviously that's what's of most interest to you and your peers. To answer your question, by no means when I say is the pricing trending down, is it sharp, I think what you find is that there's a flattening and maybe a bit of a give-up on a little bit of price. And those 2 basins, as it's been reported, is the Northeast and the Southeast, which are your gas-driven basins. We still see and I think our competitors, at least one of our competitors have said the same thing, couple of the oil basins and the basins being a little bit newer to the unconventional, if you will, or at least the horizontal drilling and multistage fracturing being woefully under supply and the wait times there for pressure pumping dates are not shrinking. But in turn, again, in those 2 basins that I highlighted, wait times have probably dropped 50% according to our data. And like I said, I don't want to go into any of the other product lines by basin, Angie, but as I look at it, the -- if I give you one more data point I'd say in those 2 particular basins as well because it's activity driven, things like drilling services and wireline services are following a little bit like pressure pumping although there hasn't been as much capacity added in things like wireline or drilling services in those 2 basins.

All right, all right. That's very, very helpful. And then as one of an unrelated follow-up, but on the international margins, 2 questions. When you think about early next year, I would assume based on your comments on cost in the third quarter that when we think through margins early 2012 that the normalized margin should be that second quarter number of 13.5% versus the third quarter of 12.2%, that's first? And then second, obviously, there's been some debate on pressure -- pricing in the international markets for 2012. Your thoughts on which markets or country should lead and lag next year?

I would certainly say that we will see the Middle East leading in margins, driven by Saudi across all product lines and some other key countries in the Middle East. And then I would say Latin America will continue with the rebound, the encouraging rebound we see in Mexico is absorbing capacity on that front, in that continent, no slowdown in Brazil, possibly a pick-up in activity in the southern cone. And of course, the NDN has no -- doesn't appear to be slowing down. So I'd say the 2 regions, if you will, will be driven primarily by Middle East and Latin America. Well, Chad, do you have any?

No, I think Russia could get a little bit better in 2012.

And are there any markets that you expect lagging or limited pricing recovery in 2012?

Well, I think a lot of that depends on us as a service industry. But I don't think anything is going to necessarily go down from here. I think it's a little premature. We have to see how the plans roll up from our customers in terms of their spend, Angie. So I hold off answering that one may be until the next time we get together.

North Africa, maybe a little bit up, Algeria is looking better, but Libya still a big question.

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

I'll chime in too Chad, I do appreciate your accessibility and candor over the years. And good luck on your next phase.

Thanks, Kurt.

Sure. So I guess the follow-up question I have here is predicated on the commentary you provided and in the general guide points you put forth in your presentation. I guess we can all infer from that shriek [ph] consensus number in the fourth quarter of $1.38 looks not only achievable, but probably beatable predicated on the product sales that you have in hand for international and as well as the North American growth. Would you guys agree with that comment in principle?

It's early on in the quarter so it's hard to say where it stands. But I wouldn't be raising that estimate.

Okay, that's fair, Peter. I'll leave that one there. All right. And then I guess, Martin, you had referenced something back as part of I think Angie's questions. I just wanted to get some point of clarification. You've mentioned something about -- in 2 basins, there are still willfully undersupplied, and that's on the liquid front and wait times are not shrinking yet. And I guess you were mentioning in the 2 gas basins that wait times have dropped $50%. I was just looking for some clarity on that.

Well, Kurt, that's one of the clarities I want to provide, but that's exactly right. The opportunity our customers have to schedule a fleet now is 50% less from what the wait times were before in the Haynesville and in the Marcellus. But that all said, the frac fleets are far less fungible if you will than a drilling assembly. So I think what you're going to find is that equipment stays landlocked a little bit more and case in point is as we move west into Ohio now, you would think that the pricing in the Utica and the wait times would reflect the Marcellus, but it's not. It's tight, its wait times are long, pricing is good, granted there's some different well-treating properties. But it's not, by any means, spreading beyond those 2 basins at this time.

Okay. I guess, I'm just kind of curious, during the comments that have come out from the growing peer group, so far to date, the reference about in aggregate the North American pressure pumping market still being tight and extremely tight, obviously, in the liquids basins and I guess some state of excess in the gas basins. Typically, in this business, if the market is tight and it's undersupplied, the service companies get very good pricing. So I'm just kind of wondering why with things still relatively in short supply how come pricing isn't better.

Yes. Well, that's -- I think what you're finding though is if we take a typical well now, things are a little bit different than in the past. The well -- the frac cost on a typical unconventional, let's take the Eagle Ford, is 50% of the AFP, Kurt. That's a significant amount of spend, in the last cycle wasn't there. The pressure pumping invoice was probably -- at best half of that in the total well completion -- total well AFP. So I think what you're finding now is that the economics on the wells is very much affects the pricing we're able to achieve on such a big portion of AFP. And I think it's also why you see a pretty big backlog of wells drilled but not completed, because maybe the economics don't work. So it's a very good question, but I think again in some of those basins where the wait times haven't dropped and they're woefully undersupplied, as I've said, pricing is still going up, but also the acceleration of that price while going up is not as high as it was in the past.

Okay, and then maybe a last follow-up on Latin America, you referenced Mexico coming back or being a pretty strong contributor. If we were to look at the varying countries and contributions of varying countries within Latin America, where would Mexico rank relative to Brazil at this point? And your expectation as to where Mexico may rank as you head out in 2012?

When you say contribution...

Yes, on -- if you want to talk about revenue, if you want to give some -- and once again, this is all net relative, you don't want to give numbers per se, but is Mexico still your largest contributor in the Latin American market or is Brazil leapfrogging Mexico?

For us, Mexico is not our largest contributor, but certainly, I think that if you look at differential growth for the next 12 to 18 months from where it started, Mexico could very well be out in the lead of the pack on an incremental revenue growth, percentage-wise.

Your next question comes from the line of Ole Slorer with Morgan Stanley.

Peter, first question to you, just some clarification on the tax rate, which came in a little lower than what you had previously guided and the reasons for this. And also some kind of color on what you think you should be modeling for 2012.

Sure. Just -- taxes can move up and down depending on where your settlements are with various authorities around the world. We had about $23 million of discrete items benefit us in Q3, which is -- explains all that difference, which is higher than we had planned and we are expecting similar sorts of benefits in Q4 compared to the average for the year. With respect to 2012, it's too early to tell and I know you'd love to know the number, but we haven't done our plans yet. But if international margins continue to improve year-over-year, which I think they will, that's going to help some in lowering the overall rate from 2011, but probably not as low as what we've achieved in Q3 and what we projected to achieve in Q4.

Because historically you have been guiding 34%, 35%, so this should take it towards the lower end of that range, perhaps?

If you want, but we'll probably -- we'll give a better sense of guidance next quarter.

Okay. Second question on just the seasonality in the business has, of course, changed quite a bit since you absorbed BJ. So Martin, how should we be thinking about the bridge from the fourth quarter to the first quarter? Canada will of course benefiting you on the strong side, but on product sales will temper off, and then maybe a little bit going into the second quarter as well given the Canadian effects versus recovery in Russia and other areas. Could you just help us a little bit on how to think about the seasonality?

Ole, this is Chad. I think you can look back over the last several years of what we have seen, and usually Q4 is a very, very strong quarter for us as you all know. Obviously, as you talked about the BJ, pressure pumping will help offset some of that product sales, but I think you'll see the same thing. Q4, we're expecting a very good Q4 quarter, and I think Q1 will be good, but I wouldn't be surprised if you don't see a little drop-off in Q1 from the international and everything else. But it should still be a good quarter in Q1.

Because Canada should be very strong sequentially, right from the fourth quarter to the first quarter?

Yes. Canada looks -- and as you said Q2 -- we know it's going to happen in Q2 regarding Canada, but Canada will be strong in Q1.

So do you think that you'll have a modest net setback in sequential margins or could it be flat?

I think you should expect a modest setback just like we've done in the past.

Your next question comes from the line of the Brad Handler with Crédit Suisse. Brad Handler - Crédit Suisse AG, Research Division: Going back to Q4 please, I guess I'm just curious about the Middle East, Asia Pacific region with some of the wins that you've highlighted, whether it's Algeria and Iraq and Al Khafji. How should we think about start-up costs, mobilization costs in Q4? So how might we think about margins in that region, specifically?

Well, I think there will be some start-up costs in Iraq. Obviously, with the LUKOIL win because we are -- we've been kind of gearing up for that for the last couple of quarters anyway because we've known we've had it for a while. You know that Khafji is not going to be a major start-up cost operation, this is something that nobody shared in for the last 38 years, so we're pretty excited about that 60% of that contract, but we have the equipment in the area that we're able to move in there. And, of course, when you're sitting in Kuwait, you're sitting in Saudi already as strong as we are, but not like you don't have the asset. So I don't think Q4 is going to be a very huge hit for us on start-up other than a little bit in Iraq. Brad Handler - Crédit Suisse AG, Research Division: Okay, all right, that's helpful context, I appreciate that. Maybe the related follow-up is so if we were to think about the individual regions and the contribution coming from each of them in the fourth quarter sequentially, is it fairly well balanced in terms of basis points of margin improvement? Or does one region wind up driving it in your -- based on what you see can see today whether it's from product sales or from reversal of costs or what have you?

Well, I think one thing to look at in Q3 and then understand why we're pretty optimistic about Q4 is here we have one particular area that took a pretty good hit in Q3, and that was Europe and Martin highlighted it in his conversation. But Europe was down from its normal operating margin by several hundred basis points for the various things that Martin talked about, the mix, a little bit of FX, a little bit of R&O, the different things in there. Europe traditionally is a strong area for us. It has been all this year, and we see it bouncing back in Q4. So that right there, we get a lot of comfort knowing Europe is coming back in Q4. So that will make up a lot of the difference you saw over Q3. Brad Handler - Crédit Suisse AG, Research Division: That make sense. So in others, as we look at Latin America and the Middle East sequential performance on the margin basis, that was much more attributable to mix?

Yes. The other regions were okay. They had a little slip here and there, things that we talked about. But most of the hit in Q3 came out of the Europe region.

Your next question comes from the line of David Anderson with JPMorgan. John David Anderson - JP Morgan Chase & Co, Research Division: I just want to get back to North America, if you don't mind. You guys have some pretty bullish comments on the market, glad to hear that. I just wanted to ask a bit more about your capacity additions going into next year. You talked about ramping up. I think you're saying 1 fleet every -- one 40,000, 50,000 fleets every 6 weeks. How does that shift going to next year? Are you thinking about next year? Are you going to continue to have this pace all next year? And then how do you thinking about kind of this looming oversupply situation everybody's kind of freaking out about? I mean is that still going to be a second half '12 event in your mind or is that -- or where do you come out there?

Martin, you take that one?

Sure, Chad. David, this is Martin. Let me say it this way, we are planning to increase the horsepower per period. I'm not prepared yet until we fully map this out going into the fourth quarter and load the line, if you will, to give you an exact as we have in the past in terms of a fleet every 6 weeks. But I think it's safe to say that based on what we're doing now, we'll be able to do better than that on average in '12. And in terms of this what everybody is excited about, this overcapacity hang, David, the fact of the matter is that our customers continue to absorb more and more horsepower. They're drilling longer laterals. They're putting more stages as you've seen in this OptiPort job that we did 49 stages in the Barnett. There's really no better way to extract these reservoirs than to continue to drill longer, put more fracs on and even perhaps tighten up the well spacing, which is only going to accelerate again this absorption of capacity. It's not to say that it's a never-ending trend. Obviously, in some basins, particularly, the Haynesville, the lengths haven't gone, haven't extended for over a year now. They're pretty much flattened out. But all the other basins are showing continuing lengths. So our internal model as well as some of the -- peer group, the published, the frac models, we remain convinced that the market's not going to be properly supplied on the pressure pumping front through '12. And that's -- of course, there's the macro issues out there that commodity prices and economic -- general activity and so forth. But the way things looked now, we don't see a capacity issue in '12. John David Anderson - JP Morgan Chase & Co, Research Division: In '12, okay, that's great. The BJ fleet, are you done kind of replacing what you thought you had to replace? Are you at the point now where you're kind of building your overall capacity level?

Yes, definitely. John David Anderson - JP Morgan Chase & Co, Research Division: Okay. And then I guess a little bit of a change going into Gulf of Mexico. Your comments have gone a little bit more positive than there has been the last couple of quarters. Just want to get a sense, you're talking about how your margins are kind of depressed because of the Gulf. Can you give us a sense as to how much it could improve your North American margins? I mean right now you posted I think it was 22% margins North America. Like how much was it down because of Gulf, and as it starts picking up, is it just a question of just activity levels and does the cost get absorbed really quickly and just kind of hit the bottom line quickly? Can you just kind of help us understand that progression as you see it into next year?

David, this is Martin again. I don't want to provide too much detail on the -- on what we think our incrementals are going to be. But there is a fixed, heavy fixed cost base in the Gulf of Mexico. And I think one of the comments from our peers was that the incremental should be very good, and we've seen that. But the fact of the matter is, probably what's most important is 2 fronts to get those margins up. There's nothing more that can be done, I don't believe on the cost front nor should we based on what the outlook is. Our customers are very bullish. The permitting is getting better. Really, it's still is a highly a mix issue and the type of rigs that are running and the type of wells that are being drilled, if you look at the permits, there's still a preponderance of sidetracks and injector wells, and we're woefully underrepresented on the exploration type. And for companies like ourselves and our big peers, that's, of course, that's very different revenue mix than some of the wells that are being drilled. But as Chad highlighted, in terms of our sand control feet and the boats we're running, commissioning and getting the Tarpon ready this quarter, it was a very good quarter relative to where it's come from. And I expect that year-on-year, we're going to have a much better quarter this time next year, if nothing else changes in the Gulf.

Your next question comes from the line of Mike Urban with Deutsche Bank.

And wanted to offer my best wishes to Chad as well.

Thanks, Mike.

So the -- it seems like you're on track to hit your long-held 15% margin target internationally. It also seems that's come against the backdrop of probably a weaker activity outlook than you might have expected a lot of delays, of course, all the geopolitical issues. So can we take that to mean or imply that some of the self-help initiatives you've had underway, whether it's cost-cutting efficiencies, supply chain, all that kind of stuff, has been -- you've done better on that than you might have expected?

Yes. I think we've done better in a few areas. I think our cost-cutting area, I think that's been a good improvement. Our supply chain side is improving, but again, we've got some work still to do there. As I said in my comments, we have shifted a lot of future manufacturing capability to other parts of the world. So we've been running a little bit of duplication at a time and may be not fully up to speed in certain product centers yet. I don't think that some of the geopolitical stuff has hurt us all that much when you look at it. Yes, Yemen is down a little bit, Syria is down a little bit, we look at a few areas, but for the most part, activity has probably held in there. I think we felt from day one and we started to map out all of this 15% exit rate where it was going to come from, I think we're hitting in on most of the fronts that we targeted and we always knew that into Q3, Q4 was a strong time for us on shipments and ESPs in Russia and elsewhere. So I don't think there's any surprises out there for -- that we haven't anticipated. I think we feel pretty comfortable Q4 will be there if we can just deliver the product that's already been sold. So that's the key.

Okay. That's helpful. And shifting over to North America, Martin, I think it was you that said you don't see -- there's not necessarily a tremendous amount of fungibility in terms of equipment in the pressure pumping markets. Is there anything that you can do to address that and potentially smooth out some of those variances from basin to basin or even if you do see a slowdown in North America, the ability to move some of the stuff internationally to kind of manage the supply globally like skidding frac fleets and things like that?

Mike, by no means do I want to suggest that we don't roll the fleets to other basins, and we do that now, and it's happening. But relatively speaking, moving one wireline truck or moving a 40,000-horsepower fleet is a very different task. So on the scale of mobility, if you will, frac fleets are way down the curve. So it's going to take a little longer to reposition and so forth. The second part of your question was what, Mike?

Could you also address the...

The international front. So a certain percentage, I don't want to say what, of the fleet that's scheduled to come out in the first half is skid mountable and transferable for that reason that if we should start to see second half of next year, a balancing, approaching where we reassign it to Latin America, Middle East, particularly Saudi with the unconventional attention and, of course, parts of Europe.

So your flexibility on that front in terms of being able [indiscernible] around is improving?

It's very good. It's well thought out and understood and that's the way we're building.

Your final question comes from the line of Bill Sanchez from Howard Weil.

Peter, I just wanted to ask you on Canada I know in the second quarter you mentioned that you had expected to recapture about 2/3 of what you lost in 2Q in the third quarter, I'm just curious I know there was wet weather in July. Were you able to do that, make that target?

Yes, pretty much. Canada was no surprise in Q2 and met our expectations. Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division: Okay. And then just as a quick follow-up on Latin America. I think when you guys outlined a 15% margin expectation as we exit 2011, my recollection was is that Latin America margins would probably be just shy of that. I mean given where your margin performance was in 3Q, can you just talk about how we should think about Latin America here fourth quarter? And I guess Martin some mix issues there that perhaps are going to continue to be a challenge for you as you think about going into 2012.

Just let me balance the map and maybe Martin will talk about mix. But we said Europe will be our biggest sort of recovery going into Q4. So we expect that region probably to be in the higher end of the 3 international regions. And it's kind of a toss-up if it's Middle East, Asia Pac or Latin America, probably below the average, right?

As far as the mix side, Bill. On the geography side, I don't see any slowdown in the Andean region at all. Very bullish, great terms for our customers, optimism, execution performance by our customers and geological success. Brazil, no temperament, both in terms of Petrobras, as well as the local operators like OGX and the foreign interest. And as I said, on a revenue contribution side year-on-year, I think Mexico could be the star if everything lines up properly.

Okay. And those margins in Mexico, Martin, relative to the segment average, better, worse, in line?

I think let's say by the middle of the year based on the revenue volume, it'll probably be about middle of the pack.

Thank you, Chad, Martin and Peter. I want to thank all of our participants this morning for your time and your thoughtful questions. Following the conclusion of today's call, I will be available to answer your calls. Once again, thank you for your participation.

Thank you for participating in today's Baker Hughes Incorporated Conference Call. This call will be available for replay beginning at 8:30 a.m. Eastern, 7:30 a.m. Central and then will be available through 10:00 p.m. Eastern on Tuesday, November 15, 2011. The conference ID number for the replay is 11523813. The numbers to dial for the replay is (855) 859-2056 in the U.S. and (404) 537-3406 international. You may now disconnect, and thank you.