Baker Hughes Company (BKR) Q2 2013 Earnings Report, Transcript and Summary

Hello, my name is Lorraine, and I will be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Second Quarter 2013 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Trey Clark, Vice President of Investor Relations. Sir, you may proceed.

Thank you, Lorraine, and good morning, everyone. Welcome to the Baker Hughes Second Quarter 2013 Earnings Conference Call. Here with me today is our Chairman and CEO, Martin Craighead; and Peter Ragauss, Senior Vice President and Chief Financial Officer. Today's presentation and the earnings release that was issued earlier today can be found on our website at bakerhughes.com. During the course of this conference call, we will provide predictions, forecasts and other forward-looking statements. Although they reflect our current expectations, these statements are not guarantees of future performance, but involve a number of risks and assumptions. We urge you to review Baker Hughes' SEC filings for a discussion of some of the factors that could cause actual results to differ materially. Lastly, reconciliation of operating profit and other non-GAAP measures to GAAP results can be found on our earnings release and on our website at bakerhughes.com under the Investor Relations section. With that, I'll turn the call over to Martin Craighead. Martin?

Thanks, Trey, and good morning, everyone. Let me start off with a few comments about our results. First, Baker Hughes performed well in North America and across the Eastern Hemisphere this quarter. In fact, the Eastern Hemisphere posted record revenues on strong growth in both Europe/Africa/Russia Caspian and Middle East/Asia Pacific business segments, while North American revenue increased 3% sequentially despite Canadian activity reaching its lowest level in 4 years. Unfortunately, that performance was more than offset by profit erosion in our Latin American business segment. So I want to begin my remarks today by addressing these issues right out of the gate. First, the most meaningful issue we faced in the quarter was timing associated with the ramp-down of our drilling contract in Brazil. As we transitioned to the new contract structure in the second quarter, we made a conscious decision to work with our customer and ensure there were no operational disruptions. This customer-centric approach in Brazil has served us well over the years, and that, coupled with stellar drilling performance, secured us a contract extension last year, which resulted in very high activity levels being reached in the first quarter of this year. As we progressed through the second quarter, we were anticipating a further extension. Unfortunately, that did not occur, and as a result, we forfeited an opportunity for a more orderly demobilization. This left us with stranded costs associated with elevated staffing and underutilized assets. Also during the quarter, we faced the well-publicized shutdown across northern Mexico. Accordingly, late in the quarter, we began the process of reducing our cost structure. We've made adjustments to headcount, began redeploying assets and wrote off some obsolete inventory, and we have more to do. Based on the actions we're taking, we expect an immediate improvement in margin performance and recovery to high-single digits by year-end. Unfortunately, these issues overshadowed growth and improved performance in other regions during the quarter. In Norway, for example, we have ramped up for one of the largest integrated drilling service contracts in the history of our industry. This, coupled with strong activity in Russia, Nigeria and the U.K., grew our Europe/Africa/Russia Caspian segment by more than 13% over the previous quarter, with incremental margins in excess of 50%. Our Gulf of Mexico business recorded its historical best revenue, with strong incremental margins, while our U.S. Pressure Pumping business posted its second consecutive quarter of improved revenue, share and margins, as it executed more stages, with more 24-hour fleets than at any point in our history. Later in the call, I'll provide more details on the balance of our business segments, but first, let me turn it over to Peter for details on the quarter and our guidance. Peter?

Thank you, Martin, and good morning. This morning we reported net income for the second quarter of $240 million or $0.54 per share. This includes a $20 million or $0.05 per share after-tax reserve for bad debt in Latin America, as well as a $7 million or $0.02 per share after-tax inventory charge related to certain profits in North America. Revenue for the second quarter was $5.5 billion, a record for Baker Hughes, which was up $257 million or 5% compared to the previous quarter. EBITDA for the second quarter was $860 million, down 1% sequentially. To help in your understanding of this quarter's results, I'll bridge last quarter's earnings per share to this quarter. In the first quarter, we posted net income of $0.60 per share. First, add back $0.05 for the currency devaluation in Venezuela during the quarter. This brings us to the first quarter adjusted earnings per share of $0.65. Next, subtract $0.02 for North America operations as significant profit improvements in the United States, both on land and offshore, were more than offset by seasonal activity reductions in Canada, including severe flooding at the end of the quarter, which, in and of itself, reduced earnings by $0.02. Add $0.10 for Eastern Hemisphere, primarily due to a strong rebound in our Europe/Africa/Russia Caspian segment. Subtract $0.12 for Latin America due to reduced revenues and stranded costs in Brazil, as well as the Chicontepec shutdown in Mexico. Add $0.02 for Industrial Services, and subtract $0.02 for higher interest expense, taxes and noncontrolling interest. At this point, our earnings per share would have been $0.61. To get the GAAP earnings per share of $0.54, subtract another $0.05 for the bad debt reserve in Latin America, add $0.02 for the inventory charge in North America. In Table 5 of our earnings release, we provide adjusted financial information, excluding the impact of the Venezuela currency devaluation, on our segment results in the first quarter. From this point on in the conference call, any comments on revenue, operating profit and operating profit margin refer explicitly to Table 5 in our earnings release unless otherwise stated. Revenue in North America was $2.7 billion, up $74 million or 3% sequentially. This growth was achieved despite seasonality in Canada, as strong revenue growth was realized in the U.S., particularly in our onshore Pressure Pumping product line and in our Gulf of Mexico business. Excluding the inventory charge, North America operating profit would have been $222 million, down $13 million sequentially. Operating profit margin would have been 8.3%. Operating profits were sequentially lower primarily due to sales mix as high-margin Canadian revenue was replaced with lower-margin Pressure Pumping revenue. In the U.S., despite a flat onshore rig count, our Pressure Pumping product line delivered improved revenue, operating profit and operating profit margin for the second consecutive quarter. Improved fleet utilization and record stages per day, resulting from increased 24-hour operations, market share gains and growing well count, contributed favorably. These gains were partially offset by continued pricing declines. Our other product lines in U.S. land also benefited from increased activity and improved drilling efficiencies, realizing higher revenues and profits, including record performance in drill bits, completion systems and Upstream Chemicals. In the Gulf of Mexico, we experienced a strong sequential rebound in revenues and profits due to higher activity, the successful introduction of new technologies and a favorable mix of deepwater development work resulting in higher utilization of our stimulation vessels. And finally in Canada, our revenues and profits declined significantly, as rig counts dropped more than 70% sequentially to their lowest levels in 4 years. Compared to last year, Canadian profits were down about $0.03 per share. Moving to international results. We posted record revenue of $2.5 billion, up $156 million or 7% versus the prior quarter and up $161 million or 7% compared to a year ago. Excluding the $20 million reserve in Latin America, international operating profit would have been $268 million or 10.8%, down $13 million sequentially. Despite record revenue, our international profits were negatively impacted by our Latin America segment, where revenues and operating profits declined significantly during the quarter. The revenue decline is primarily related to Brazil, where our activity and share both declined during the quarter as we transitioned to a new drilling services contract at lower prices. Operating margins in Brazil were further reduced by stranded costs, such as severance and obsolete inventory charges. In Mexico, performance dropped due to the well-publicized shutdown of activity in Chicontepec. In our Eastern Hemisphere segments, we delivered revenue growth of $189 million or 11% sequentially, with 30% incremental operating profit. Our Eastern Hemisphere operating profit margin was 13.7%, up 170 basis points sequentially. Among our Eastern Hemisphere segments, Europe/Africa/Russia Caspian experienced the most significant improvement in revenue, operating profit and operating profit margin. Segment revenues grew $112 million or 13% sequentially to a record $966 million, with 52% incremental operating profit. Operating profit margins were 15.6% in the second quarter, representing a sequential increase of 470 basis points. The revenue and profit increase is primarily due to increased activity in the North Sea, Nigeria, Mozambique, Angola and Russia. In Norway, revenues and margins were further enhanced by performance-based bonuses associated with our new integrated drilling services contract, even while we were finalizing our mobilization during the quarter. Our Middle East/Asia Pacific segment delivered continued revenue growth, posting record revenues of $971 million. This represents an increase of 9% sequentially and 21% year-over-year. The sequential improvement was primarily due to increased integrated operations activity in Iraq, where we now have 12 operational rigs, as well as higher activity in Saudi Arabia, Malaysia, Vietnam and Australia. Operating profit was down 110 basis points sequentially, however, primarily due to higher third-party passthrough revenue in Iraq and mobilization costs associated with our second Pressure Pumping fleet in Saudi Arabia. For our Industrial Services segment, revenue was $316 million, up $27 million sequentially. Operating profit was $39 million, up $15 million sequentially, and operating profit margin was 12.3%. Increased revenues and profits were primarily due to seasonal improvements in our Process and Pipeline Services business. Looking at the balance sheet. During the quarter, we generated $230 million of free cash flow, ending the quarter with a cash balance of $1.1 billion or a $22 million increase sequentially. Total debt decreased $183 million during the quarter to $4.9 billion. Currently, our total-debt-to-capital ratio is 22%. Capital expenditures for the quarter were $551 million. Now let me provide you with our guidance for the remainder of the year. In the U.S., we are reducing our onshore rig projections from our last guidance. However, activity is still projected to improve. In the second quarter, we exited with 1,692 rigs. We anticipate that the rig count will rise modestly to an average of 1,720 rigs by the fourth quarter or an increase of about 30 rigs between now and the end of the year. The forecast for U.S. offshore rigs remains unchanged, with an average of 52 rigs in 2013, which is an increase of 4 deepwater rigs or 8% compared to 2012. The total average annual U.S. rig count for 2013 is now projected to be 1,765 rigs, composed of approximately 1,385 oil rigs and 380 gas rigs. This represents an 8% reduction compared to 2012. However, we expect that drilling efficiencies will continue to improve during the remainder of 2013. We currently forecast the U.S. onshore well count for 2013 to be approximately 35,000 wells, which is a reduction of about 4% year-on-year. In Canada, the average rig count in the second half of 2013 is projected to increase to 335 average rigs in Q3 and 375 rigs in Q4, which is slightly better than last year and up from our previous guidance. As a result, Canada's average annual rig count is now expected to be 350 rigs. Sequentially, we expect Q3 North America profit margins will improve. The seasonal return of activity in Canada, increased utilization of our U.S. Pressure Pumping fleet and continued strong demand for our other product and services in the United States are all expected to improve revenues and operating profit -- and operating margins. Gulf of Mexico results should remain strong, presuming there are no weather-related disruptions. Looking internationally, the rig count is anticipated to continue recent growth trends in the second half of the year, yielding an average 2013 rig count of 1,360 rigs, with increases in every region. Excluding Iraq, this represents a 7% increase in the annual international rig count. Looking at our international margins, we expect that our Europe/Africa/Russia Caspian segment margin should continue to increase in the second half, driven by activity improvement and newly win share in the U.K., Nigeria, Sub-Sahara and Russia. Our Middle East/Asia Pacific segment margins should rise during the second half of the year also, as unconventional gas activity in Saudi Arabia increases and as profitability increases in Iraq. And in Latin America, we expect operating profit margins to improve in the third quarter due to new projects starting in the region and ongoing efforts to reduce costs. We expect that profit margin should be in the high-single digits by the end of the year. Industrial Services activity in Q3 is expected to be similar to Q2. Q4 margins, however, are expected to be lower due to seasonality in our Process and Pipeline Services business. Also for the third quarter, interest expense is expected to be around $60 million. Corporate costs are expected to be about $70 million. Depreciation and amortization expense is expected to be around $430 million. Capital expenditures for the quarter are expected to be about $550 million, and finally, our full year 2013 effective tax rate is expected to be between 33% and 34%. At this point, I'll now turn the call back over to Martin. Martin?

Thanks, Peter. As I mentioned earlier, we are reducing our Latin America cost base to improve its profitability. Actions underway include the adjustments to headcount, as well as the redeployment of critical assets and skilled personnel to support the strong growth we are capturing in other markets, specifically in Norway and the Middle East. At the same time, we remain committed to long-term profitable growth in this region and continue to target projects aligned to our core strengths, particularly in deepwater, unconventionals and integrated operations. During the second quarter, we have secured additional contracts across the region that will help backfill the revenue drop in Brazil and Mexico. As an example, in Argentina, we have been awarded a major contract to provide integrated completion services for unconventional development. The scope of work includes a frac fleet, coil tubing, wireline services and completion systems. We will also be playing a key role in the development of unconventionals in Colombia, where we have been awarded a 9-well project for drilling services. And looking beyond 2013, last week, we were awarded the Soledad block in Chicontepec. This long-term integrated operations project will provide a sound reentry point for us into northern Mexico beginning early next year. Now turning to our Eastern Hemisphere operations. I'm very excited with the outlook. Our operations are benefiting from new technology deployment in a number of key markets, steadily growing activity and improving operational efficiency. In Russia, we completed the industry's first fracpack operation in Sakhalin. This is the first of a multi-well completion campaign and represents the largest sand control project for Baker Hughes in the region to date. In the neighboring Caspian geomarket, we received a letter of award for a 3-year campaign to provide drilling services in Turkmenistan beginning this quarter. In Africa, we're excited about our growing position in the emerging deepwater market off the east coast. During the second quarter, we secured a series of contracts that further enhance our position to now include a sizable onshore presence in this important and growing market. Baker Hughes will provide wireline services, drill bits and cementing on a multi-well exploration campaign, spreading over the next 5 years across Kenya and Ethiopia. Also in Africa, we've been awarded a 4-year contract to provide wireline services on an ultra-deepwater campaign in Angola and Namibia. And in offshore Malaysia, we have completed our first well under a new integrated operations contract for a multi-well campaign. The work scope includes coil track services, representing the first time we have provided coil tubing drilling services offshore in Asia Pacific. Across the Middle East, development of the unconventionals is becoming a growing market driver. Saudi Arabia and Oman are both actively targeting shale gas and tight gas production. Additionally, there are potential projects in the United Arab Emirates and Kuwait. With Pressure Pumping assets now mobilized in the region, we are well-positioned to capture strong growth in this market. These are just a few of the operational highlights in the Eastern Hemisphere that will continue growing international revenue and margins in the second half of the year. Turning to North America. As new technologies and methodologies continue to be introduced into the unconventional market, drilling efficiencies improve. However, they don't improve consistently, not between basins and not even between operators within a basin. For the last 70 years, we have provided the industry with the Baker Hughes Rig Count. Last night, we announced the launch of the Baker Hughes Well Count. This new index captures the number of wells which were spud in each major U.S. basin and, when combined with the Baker Hughes Rig Count, drilling efficiencies become more obvious. As industry trends evolve, you can expect new features and information sources to be added to the Baker Hughes Well Count index periodically. We can see from the data, for example, that drilling efficiencies vary by basin. In the Williston, the Marcellus and the Eagle Ford, we're seeing about 20% more wells per rig compared to this time last year, whereas in the Permian, wells per rig have hardly changed. Additionally, the Baker Hughes Well Count shows seasonality that wasn't evident in the rig count alone. During the winter months, the wells per rig slows due to poor weather conditions. For example, the wells per rig dropped by 15% in the Granite Wash this past winter before rebounding later in the spring. So it's the seasonal rebound and the underlying trend of drilling efficiencies that explains why we saw a 3% increase in the Baker Hughes Well Count during the second quarter despite the rig count remaining absolutely flat. The ongoing trend to continue increasing wells per rig is a fantastic opportunity for a technology-driven service company such as Baker Hughes. We're playing a meaningful role in improving the economies of shale in North America through new technology introductions and deployments. For example, last quarter, we achieved a significant milestone by successfully introducing the cemented FracPoint system. This service provides all of the isolation and entry benefits of plug and perf completions while providing the efficiency gain achieved using sliding sleeves. In basins where open hole completions are prohibitive, such as the Eagle Ford, for example, operators now have a cemented sliding sleeve option built on the industry-leading FracPoint system. We are driving efficiencies in our Pressure Pumping business through technology introduction. Last year, Baker Hughes was the first to announce the introduction of hydraulic fracturing pumps able to operate on diesel and natural gas. And today, we remain at the industry forefront of bifuel deployment. Demand for our Rhino Bifuel has been outstanding. In this quarter, we completed several stimulation treatments in the U.S. and Canada using full fleets of bifuel-capable frac units. Today, in collaboration with a growing client base, we offer this technology using either LNG, CNG or the customer's own line gas. We are accelerating the deployment of Rhino Bifuel throughout North America by retrofitting several existing fleets in order to have the largest number of bifuel fleets available to the market. And we believe bifuel-powered pumping technology will rapidly become this industry's norm. Pressure Pumping pricing remains low, but we believe it has stabilized. However, even in a poor pricing environment, we continue to increase profitability of this product line through the actions we are taking to improve operating efficiency and fleet utilization, including the introduction of new technologies. Now turning to one of the most exciting areas of our North America business, the offshore market. The ongoing shift within the Gulf of Mexico to include more development work is playing to our strength in completions and production. In the second quarter, we achieved an industry first. Using our Blue Dolphin stimulation vessel, we performed 6 individual multi-zone fracpacks on a single well in a single trip. The project required high pump rates and high volumes, including the largest volume of proppant ever pumped into a single well in the Gulf of Mexico. For any other lower-volume vessel, this project would have taken multiple trips to shore to resupply or multiple vessels on location. Recently, we announced the addition of a third vessel to this growing market, and this afternoon, we will take part in her christening. She is deepwater capable and is planned to be operational later in the third quarter. We're also introducing new capabilities on the Drilling & Evaluation side. And during the second quarter, we successfully completed a high-profile evaluation operation on an ultra-deepwater high-temperature appraisal well. The project included the deployment of several recently introduced wireline technology services, including RCX Sentinel, focused sampling, GeoExplorer imaging, MaxCOR rotary coring and Nautilus high-pressure high-temperature logging. Our strength in North American offshore markets is also growing north of the border. During the second quarter, we gained drilling services share in the offshore market in eastern Canada, advancing our foothold in this small, but yet very critical market. In the past, I've talked about 3 technology-based themes underpinning long-term profitable growth for Baker Hughes. They are: increasing well complexity, improving drilling efficiency and improving ultimate recovery. Now the majority of our technology investment is aligned accordingly, and today, I'd like to highlight a new breakthrough product that takes a substantial step towards addressing the third theme, ultimate recovery. Our artificial lift product line has been testing a promising new technology to boost production rates and ultimate recovery for unconventional shale wells. As you know, these wells have a very steep decline in production in the first few years, so the challenge was to develop an electrical submersible pump that could operate at low -- at lower flow rates typically associated with rod lift products, while providing the reliability and overall efficiencies of an ESP. The new FleX pump series ESP does just that. It is engineered to handle a broader range of production rates and can operate in low-flow wells, down to 50 barrels per day. This is the right product at the right time, and it expands our North American ESP market by over $1 billion. And it provides our customers with a more sophisticated solution, one that provides superior reliability and variable drawdown capability. We successfully field-tested FleX pump in the Eagle Ford, the Bakken, the Permian and the Central basins. And in some cases, these early tests are showing production increases up to 35%, along with more reliable gas handling at lower pump pressures when compared to traditional rod lift systems in offset wells and like all ESPs, without the normal tubing wear caused by rod lift in deviated wells. This has the potential to be the next great breakthrough in artificial lift technology, and it's innovations like the ones I've just mentioned that will drive long-term profitable growth here at Baker Hughes. At the same time and equally important, we remain 100% focused on the near term, improving the quality of our earnings, remaining capital-disciplined and generating free cash [ph]. And with that, Trey, let's turn it over for some questions.

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

[Operator Instructions] And our first question comes from James West from Barclays.

Martin, as you think about North America in the second half of the year, you obviously highlighted a lot of traction, or good traction in your pumping business in terms of utilization. We've got the new ESP that you just mentioned and went through the technology there. You've also got some strengths in production chemicals, things like that. Yet, it looks like kind of estimates, at least our estimates, other estimates out there, have a pretty wide margin gap between yourself and some of your peers. And admittedly, we haven't seen one of your peers' numbers just yet. We'll see those on Monday. But how quickly do you think -- or I guess, 2 things. I guess, one, do you think that there is a structural gap between your margin potential and theirs? And two, if not, how quickly do you think you can close that margin gap?

That's a great question, James. Thanks for asking it. First of all, there's not a structural impairment. As we've highlighted before, our -- one of -- our largest product line in North America is operating at differentially low performance, economically. That all said, it's making -- it is the product line with the most momentum in terms of improvement across the globe for us right now. So it's a locomotive that is starting to churn out, and it made some very nice improvement and as I highlighted, 2 quarters in a row. In this particular quarter, the slope of the curve is picking up even more. So it's really starting to come together. And in that -- and that is the only issue that we -- I believe we have in North America. We like our portfolio, we -- both in terms of product line and in geographies. Highlighted the diversifications going on in Canada, the strength in the Gulf of Mexico, our mix with our ships versus our peer group, and the non-pressure pumping businesses are performing extremely, extremely well. And in that particular business, if you remember, about a year ago, a little over a year ago, we highlighted the issues that we were facing, and one of the most critical, at the time, were the -- was the people utilization, an action was taken and realignment made. The customer mix is pretty much where we want it to be, and the big issue there was having the right customers in the right locations, and being able to get on 24-hour operations, and that's behind us. I think the issue still lies around some issues around transportation and logistics, and those are things we're still working through. So no structural. And in terms of timing, I don't want to put my finger on that because it's a volatile business, as you know. But for us, we don't expect any more price erosion going forward. We did experience a little from 1 to 2, but I think that's behind us, so it's upward and onward from here.

Okay. And the transportation issues that you highlighted, I mean, those don't seem like -- I'm not trying to pin you down too much on timing, but they don't seem like that's an issue that's going to take years to progress. I mean, it seems like in a couple of quarters or something where you can kind of fix those issues. Is that a fair assessment?

It's not -- that's a fair assessment. It's not years, that's for sure.

Right. Okay, good. And then just one last follow-up for me. You're over 50% utilization, I believe -- or 50% 24-hour operations on pumping today. That originally was the goal, I believe, for year-end. So what's the new goal now?

Well, I'll tell you this, this time next year, I'm hoping that it starts with a 7. But we're not at 50%. There's -- we have -- we hit 50% a couple of times in the quarter, the high midweek times, but it's really averaged around 45%. I just want to calibrate it a little differently here.

And our next question comes from Bill Herbert from Simmons & Company. William A. Herbert - Simmons & Company International, Research Division: Sort of tackling the North American margin question a little bit differently. In a world in which we have relatively range-bound commodity prices and a continued positive delta between kind of well count and rig count and E&P capital spending moving methodically higher, what do you think is a reasonable expectation for targeted normalized North American margins? What should -- what do you think -- in that kind of world in which we're growing but not melting up and we continue to prosecute the North American growth story, yet the rate of change remains relatively methodical, what should be the normalized margin after you make all these adjustments which have plagued you from a sort of operational standpoint, logistical standpoint, supply chain standpoint, et cetera?

Well, if you also factor in what you didn't mention, the -- hopefully, capital discipline that begins to permeate the service sector as much as it's permeated our customers, I'd say, if that's sustainable and pretty much around the Pressure Pumping business, once the cost of capital -- we all start earning our cost of capital again, I'd say mid- to high-teens is probably a fair expectation, assuming no sharp swings in the market.

And Bill, this is Peter. Don't forget, you still got an overhang on that Pressure Pumping capacity somewhere circa 20%, and that's kind of an unnatural position for the industry to be in. So if that overhang melts away through attrition, which we expect it will with, like you said, well count increasing, then that's -- I think what Martin said is easily achievable. But that's going to -- again, that's going to take quite some time to get that overhang out of here so... William A. Herbert - Simmons & Company International, Research Division: Right. Peter, don't worry, I'm not going to go to high-teens margins right away. But I hear you, and that is a valid point. Martin, with regard to year-end, is it unrealistic or unreasonable to expect -- I mean, you're going to get a seasonal recovery in the third quarter with regard to Canada. We've got the new frac vessel being deployed in the Gulf of Mexico. We've got ongoing utilization gains domestically. Is it unreasonable to assume that North America margins by year-end kind of get to somewhere approaching the low-teens?

I don't know if that's unreasonable, but I think that's maybe on the optimistic side of where we think. Again, the big part is the recovery in the Pressure Pumping business. And remember, to follow up on your first point, correct in 2 to 3 in Canada. 3 to 4 in Canada is obviously nowhere near as dramatic, so that's a big factor as well. William A. Herbert - Simmons & Company International, Research Division: Understood, and that's what I've got modeled. But essentially, low-teens ambitious but doable is what I'm hearing for year-end. Is that correct?

Yes, ambitious is definitely correct.

Yes, I'd probably box it in a little bit more. I'd say it's ambitious to be in the low-teens. It's plausible, certainly, to be double digits. William A. Herbert - Simmons & Company International, Research Division: Okay. And then, secondly, with regard to Latin America, I'm not sure if my math is all that crisp, given all the adjustments that we made. But I mean I get to kind of -- after you back out the bad debt provision, something around a 1.2% or 1.3% margin for the second quarter, something like that. And then you guys mentioned a high-single digit margin, hopefully, by year-end. What should we assume for the third quarter, just as a guess? And moreover, revenues for second half of the year in Latin America, is it reasonable just to assume that we're going to be flat-ish with the second quarter? So help me on top line, as well as for second half of the year, in Latin America and margins for the third quarter.

Revenues for the second half, we've got new projects starting up. I would say -- we tend to view Q2 as pretty much an anomaly with -- in terms of revenue and certainly, in terms of costs. So revenues ought to be up a little bit second half with new projects. And we would -- and we are expecting improvement in Q3 over Q2 after adjusting out the bad debt. So it may not be exactly linear between what we said our exit rate would be, but certainly an improvement from here.

And our next question comes from Jim Wicklund from Crédit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: From a technical point of view -- I know that you guys internationally -- and you talked about Eastern Hemisphere, which was great. From a technical point of view, there's been a lot of talk about who is and isn't making up ground on industry leaders, and I know you guys have lost a little bit of market share over the last year or 2 to some of your competitors. Is this a recapture of market share based on technology, just a reversion to the mean of activity? Is it being led by technology? Can you talk a little bit about the slow grind up internationally that we've seen for years? And you guys are setting records. I'm just -- a little bit more of a deep dive into what the Baker Hughes internal effort is in that regard. What are you trying to lead with?

Jim, it's -- as you know, it's -- there's always a heavy, heavy theme of technology deployment in that part of the world. That -- I can't say that, that's changed over the last, let's say, 5 years. The differentiating component for us has been the absorption and maturing of the geomarket organization, which has led, I think, to some better product developments based on the fact that we've been getting closer to our customer. Also, you remember there was quite a bit of infrastructure build in a lot of places. And just being closer, having a better operation that you can work from, having still the leading products in many categories, but having that better conversation, being closer to the customer, having a single point of contact, getting out of the organizational barriers that can hinder a divisionally oriented company like we were, I think that's probably -- and that's from a -- that's a thing that just kind of just keeps growing in terms of getting better. Okay? James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay. And my follow-up, if I could, is along the same lines. I know that several -- I know you guys have increased the infrastructure internationally over the last couple of years, and now you have bases in place that you might not have had a couple of years ago. And I would assume that, that levels the playing field on competition. Can you give us an idea of about how much or percent of capital, however you want to do it, we should look at, over the last couple of years, as kind of sunk costs that now should start to deliver results, if you would, from -- on an international basis?

Yes. Jim, we've been spending $200 million, $300 million a year on infrastructure for the past almost 4 years now, so call it $1 billion, a little bit more than that on infrastructure overall. Much of that was international. More recently, we built out our bases domestically in some of the oily basins for Pressure Pumping. But the only thing we're spending money now is the tail end of finishing up some of those projects, some of those are 2- to 3-year projects. We haven't really sanctioned much new in the past 12 to 18 months, and so most of that spend is behind us now.

And our next question comes from Kurt Hallead from RBC Capital Markets.

Martin, I was wondering if you could provide us with an update on the growth prospects in Saudi and then in the other countries that surround Saudi? I think there's been some varying data points around rig activity progression for Saudi market in particular. I was wondering if you might be able to give us a quick update on that.

I can tell you what our perspective is. But let's go back a little bit so everybody can get recalibrated. Six months ago, there was a lot of excitement out there about what kind of rigs were going to be added. They didn't, but it's our understanding that they will reach their final objective. It's been pushed out, though, to probably the end of 2014, so another 18 months. But from here on out, I believe that -- we believe the rigs will begin coming into the Kingdom. So the final number that Saudi Aramco was aiming towards, we believe, will become a reality. It's just probably 6 months behind.

Okay. And then with respect to Iraq, what's the expectation in terms of the margin dilution as the year goes on? I think you've discussed in the past that the margin dilution will continue to, say, diminish. I know you had some third-party passthrough costs here. So how do we think about that evolution throughout the course of the year?

Kurt, as Peter said, we're on 12 rigs now. We'll be mobilizing for 3 more workover rigs in the next couple of quarters. This quarter, we were breakeven, and I expect that Iraq will be contributing EPS by the end of the year. Now I think the nature of the beast that we all have to understand with that market, at least the way the market is now, given the significant amount of passthrough revenue, it's going to be a dilutive -- dilutive to margins, but EPS accretive.

And our next question comes from Scott Gruber from Bernstein. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Can you provide some details on the Soledad project down in Mexico? What's the capital commitment down there? What's the expected revenue stream? A little bit on potential passthrough revenues that would dilute the margins.

Okay. I don't want to peg the revenue stream yet, Scott, or margin projections. I will tell you that we're really, really happy and excited about this. It's not a big scale project. It's 1 drilling rig, 1 workover rig. It's -- the total capital commitment over a couple of years, it's public information at least down there, so I don't mind sharing that, it's around -- between $60 million and $65 million over 2 years. But it's a nice infill drilling, workover play. We've been very successful with the Carrillo [ph] lab down there, which is in the same general vicinity where we've taken production up -- over threefold from where -- when we inherited the field less than 2 years ago. So the reservoir engineering folks, our production engineers, we've been able to really define some targets. We're drilling some horizontal wells in the Carrillo [ph], and we'll be doing that in this block. So it's a nice -- it'll turn into a nice service incentive contract for us starting in Q1, Q2 next year. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Got it. And then an unrelated follow-up. Earlier in the year, Halliburton and now here today, Schlumberger have dedicated themselves to returning more cash to shareholders. You were free cash flow positive in 2Q and margin outlook is improving here over the second half of the year. What are your thoughts regarding increasing the dividend or buying back shares?

Yes. This is Peter. We review this every quarter with the board. The good news is we now have something to talk about. Before, we haven't been free cash flow positive on a regular basis. We weren't free cash flow positive in the first quarter, so this is a pretty strong quarter for us. We're expecting future quarters to continue to deliver free cash flow. And when that starts to be delivered on a reliable basis, we'll be in a position to be able to consider shareholder distributions.

And our next question comes from Bill Sanchez from Howard Weil.

I wanted to circle back on Latin America, and I can appreciate the comments in Brazil that you made to start the call. I guess, as a point of clarification, those assets that are in Brazil that, I guess, now need to find a new home, we're targeting those in Norway, in the Middle East, I believe you said, I guess, is point one. And then number two, just to follow up on Mexico, specifically. I guess my understanding prior to this call was -- is that the company has made it a top priority to increase your share there. I know Mexico as a percentage of your overall Latin America revenue is relatively low. Now you talk about cost cutting in Mexico. I guess just try to discuss -- or if you could just spend a little time discussing the outlook, and how do you see Mexico for Baker Hughes longer term?

That's a great question. Thanks for asking it. Well, PEMEX even before the emergence of Petrobras, at least from our calculations, the product lines that we participate in, PEMEX has consistently been the largest spender in Latin America. And you're right, we've been kind of obvious by our smaller position there, and it's a variety of reasons. But we set out a while back to change that, and the cost cutting is transitory because it is still a place we're going to invest and grow and increase both share and margins. And we have a plan to do that, and we have a line of sight to some of it. The cost cutting that Peter mentioned was really around -- and fully necessary, was given the abrupt nature and the budgetary issues of PEMEX encountered in -- and cutoff spending in the north. Whatever share we have in Mexico, the preponderance of our activity is in the north, so we didn't have much in the way of to fall back on offshore or in the south. And so the cost cutting was necessary. And -- but like I say, that's -- and it kind of helps go to explaining the -- I believe Peter mentioned this, the sharp decrementals because there were some rig cancellation costs and things like that, that we had to take care of in Mexico. But as I said, as Peter said, that's kind of behind us.

Okay. As a follow-up, unrelated follow-up, Peter, typically in Canada in 3Q, you recover about 1/2 of the lost profitability you see first to second quarter. Is that a fair assumption for 3Q this year?

Yes. As -- there are a couple of data points we already sprinkled in, which is Canada this year was about $0.03 lower than last year. So we can sort of add that back. And then you've got -- we're expecting Canada in Q3 to be just as sprightly as it was last year, if not a little bit better. So your -- our biggest single swing factor from Q2 to Q3 is Canada, and it's a sizable amount, as is typical, maybe a little bit more this time around.

So very high decrementals you had on that lost revenue in 2Q. Is getting to a 10% margin in 3Q in North America third quarter, is that a reasonable target, Peter?

I think that's a possible -- possibility.

And our next question comes from Mike Urban from Deutsche Bank.

So you talked a little bit about the pushback of -- in terms of the Saudi's plans by 6 months or so, which we had heard as well. Is that just kind of stretching things out, being more operationally efficient? Or are they struggling, in some cases, to get equipment or rigs? And I guess, just the obvious difference being the tightness of the market, not only in Saudi, but in the region. So if you could give us a little bit of color on that, that would be helpful.

I don't want to speculate on the reasons necessarily for the delay. I think it had to do with getting the right rigs, getting their projects lined out. But as I confirmed on the earlier question, it's our understanding now that most of those rigs are secured and identified to be shipped to Saudi. So yes, we push out 6 months, and the tightness in the market is real. I don't want to speculate, because, I think, we all fell victim to speculating on what it may do to price 6 months ago. So I'm just going to reserve judgment, but it certainly should have an upward bias. And I'll just leave it at that.

Okay. So -- and then maybe to ask it a little more broadly. I mean, what are you seeing pricing-wise in the broader international markets? Are there pockets of strength in certain regions? Are you seeing it across the board? Is it product or service line specific? Just a little more color on that will be great.

Sure, okay. I can tell you that I was surprised by some of the reports that came in, parts of Asia Pacific, as well as parts of the Middle East, where a couple of products lines have actually increased prices, albeit small. But it's been a while since that's been visible at this level of the company. There have been some public tender openings in a couple, again, Asian countries, where the estimates came in higher than what they call the operator estimates, meaning that between the NOC and the IOC, all the bids from the big 3 service companies exceeded their desire, and that's a good signal. So there's some discipline coming in. So -- but on the other hand, Asia Pacific, I think, has been the place where needed the most improvement. In moving north of there -- outside of North Africa, there's really no place that I wouldn't be expecting that we're seeing greater buoyancy in pricing going forward. All the big contracts are kind of behind us, as been previously stated and you well know. So here it's -- to use that overused term, which is to grind higher, I think.

And our next question comes from David Anderson from JPMorgan. John David Anderson - JP Morgan Chase & Co, Research Division: Just a question on pricing on the North America side. I can see that progressing right now. Peter, I think you had said you're starting to see attrition in some of the overhang of Pressure Pumping out there. It sounds like things have been pretty rational from a competitive standpoint. Do you think you can get pricing kind of towards the end of the year. And I guess I'm just kind of curious what are you guys modeling kind of internally as you think out for the next kind of 3 or 4 quarters? Are you expecting to see pricing in some of those numbers?

In North America, specifically, we're not modeling any pricing increases. We have been getting -- well, we have been getting some price in the Gulf now for a while just because that's ramped up so quickly and everybody was short on equipment there. But in terms of land, we're not modeling any pricing increases. Pricing has held up in our other product lines, but Pressure Pumping, we're not modeling any pricing increases. John David Anderson - JP Morgan Chase & Co, Research Division: Well, like, what about on the completion side? I guess I'm kind of wondering about, say, in the Bakken, different areas like that. Are you getting any kind of better pricing in that side of the business?

It's holding up there pretty well. The -- David, it's -- for now, it's new products, new technology where you can get a premium price, whether it's on the artificial lift side or on the drilling side. But as Peter mentioned, it's pretty much a balanced market at this point. John David Anderson - JP Morgan Chase & Co, Research Division: Yes. I was just kind of curious kind of overall with all the things we continue to hear about this kind of pad drilling starting to expand in different markets. Can you give me a sense of kind of -- roughly kind of how much of your business do you think is on the pad drilling side and where you think that can go, say, over the next 12 months?

Well, I don't want to tell you this percentage, but it's -- the amount of revenue that we earned this quarter is twice what we earned this time last year. And I don't want to tell you the magnitude of that. I'll let you judge that. But it's surprising how much is being converted to these pad locations so quickly. Now that may be part -- in part because of our product mix, particularly the AutoTrak Curve and so forth, so I don't know if it's inordinately high for us. Certainly, as well, relative to last year, the way we re-architected, redesigned our frac fleets and changed our customer mix may have also accelerated us in that space. But it's 100% year-on-year on the pads. John David Anderson - JP Morgan Chase & Co, Research Division: How does the pad side impact your profitability? Let's say, we had, had 2 wells side-by-side, 1 set on pad, 1 set not on pad, can you give me a sense of kind of order of magnitude on kind of what that does to your numbers?

On the Pressure Pumping, it's between a 30% and 50% increase in margin. It's huge.

And our last question comes from Jud Bailey from ISI Group.

I had one more follow-up on Latin America, just to understand kind of getting us back to the high-single digit number in terms of margin by the fourth quarter. Obviously, you have some cost cuts you're undergoing in Brazil and Mexico. To get to that type of margin, are you relying on any projects you see coming up in either country that would help margins get up? Or is that just simply kind of rightsizing the business for the new level of activity you have in those markets?

It's a little of both. We don't stand still. We've got -- we've picked up some share in various places. We're expecting activity to pick up in a couple places in some new projects. So revenue will contribute to that, but the bulk of it will be rightsizing Brazil, and that will take us through the third quarter to get there. So it's a little bit of revenue help, but it's a lot of just rightsizing the business in Brazil.

Got it, great. And then my follow-up is on the Gulf of Mexico. Obviously, the narrative there remains pretty positive. And I apologize if I missed it, but did you say how much did -- can you say how much Gulf of Mexico revenue grew during the quarter sequentially?

We don't break that out. We didn't say it.

Okay, all right. And then just going forward, you're adding another frac boat in the third quarter. Are we still not expecting to see material revenue increases though until 2014? Or do we see some margin improvement before that since you seem to be getting better utilization on your frac boats in the Gulf?

I think you can model in some contribution in the -- towards this end of Q4 and a full utilization into 2014.

Okay. And then the FLeX pump you guys talked about on the artificial lift side, can you -- you outlined kind of the revenue opportunity there. Could you talk a little more about perhaps how quickly you think you can roll that product out commercially and how to think about how quickly that can really start to contribute to North America results?

Well, I can tell you it's going to start contributing to our results immediately in terms of changing North America margins. One product, that isn't going to happen for a while, since we have about 1,300 different products in North America. But I will tell you that we're excited by this. It's a real, I think, substantial technical innovation. We estimate -- I don't want to tell you how many billions we estimate the artificial lift market for unconventionals to be, but we have well over half of it for ESPs. But we could only play in about 15% of that spend. This takes us to about 75% of that spend. And I tell you, this is not driven out of just wanting to put a better mousetrap out there. This is being driven, over the last couple of years, by our customers asking for a more elegant solution because, in many cases, Jud, as you know, these wells have come on at 1,500 barrels a day, but they know, in 24 months, it will be 300 barrels a day, 200 barrels a day, 100 barrels a day, given the hyperbolic decline. And they'd love to start with an ESP, but if they know, in 24 months, they're going to have to put a rod lift on it, they've avoided that, some of them, 85% of them. Now we can take them down to 50 barrels a day. It's a -- it gives them a whole different -- changes the discussion substantially. So we're pretty excited. But please, don't be changing your numbers based on one product at this stage. Okay?

No, we're not going to do that.

Thank you for participating in today's Baker Hughes Incorporated conference call. This call will be available for replay beginning at 10:30 a.m. Eastern time, 9:30 a.m. Central time, and will be available through 11:30 p.m. Eastern time on August 2, 2013. The number for replay is (888) 843-7419 in the United States or (630) 652-3042 for international calls. And the access code is 34835209. You may now disconnect.