Baker Hughes Inc BHI
Q2 2013 Earnings Call Transcript
Transcript Call Date 07/19/2013

Operator: Hello, my name is Lorraine, and I'll be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Second Quarter 2013 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period.

I will now turn the conference over to Mr. Trey Clark, Vice President of Investor Relations. Sir, you may proceed.

Trey Clark - IR: 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

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 on 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 under the Investor Relations section.

With that, I'll turn the call over to Martin Craighead. Martin?

Martin Craighead - President and CEO: 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 four 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 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?

Peter Ragauss - SVP and CFO: 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 the $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 is 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 at a significant profit improvements in the United States, both online 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 cost in Brazil as well as the Chicontepec shutdown in Mexico.

Add $0.02 for Industrial Services and subtract $0.02 for higher interest expenses, 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 and 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 of flat onshore rig count, our pressure pumping product line delivered improved revenue, operating profit and operate 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.

Finally, in Canada, our revenues and profits declined significantly as rig counts dropped more than 70% sequentially to the lowest level in four 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 pass-through 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 and ended quarter with a cash balance of $1.1 billion, or $22 million increase sequentially. Total debt decreased $183 million during the quarter to $4.9 billion. Currently our total debt-to-capital ratio was 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 four 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 the 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 margins. Gulf of Mexico results should remain strong, presuming there are no weather-related disruptions.

Looking internationally, the rig count is anticipated to continue the 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 7% increase in the annual international rig count.

Looking at our international margins, we expect that our Europe/Africa/Russia Caspian segment margins should continue to increase in the second half, driven by activity improvements in newly won 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.

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 cost. 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, 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. 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?

Martin Craighead - President and CEO: 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've been awarded a major contract to provide integrated completion services for unconventional development. The scope of work includes the frac fleet, coiled-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 nine-well project for drilling services.

Looking beyond 2013, last week, we were awarded the Soledad block in Chicontepec. This long-term integrated operations project will provide a sound re-entry 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 frac-pack operation in Sakhalin. This is the first of a multiwell 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 three-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 multiwell exploration campaigns spreading over the next five years across Kenya and Ethiopia.

Also in Africa, we've been awarded a four-year contract to provide wireline services on an ultra-deepwater campaign in Angola and Namibia. In offshore Malaysia, we have completed our first well under a new integrated operations contract for a multiwell campaign. The work scope includes CoilTrak services, representing the first time we've 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 were 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 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, the drilling efficiencies vary by basin, in the Williston, the Marcellus, the Eagle Ford, we are 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 show 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 are playing a meaningful role and 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 openhole 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. Today, we remain at the industry forefront of Bifuel deployment.

Demand for 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 customers' 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. 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're 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 six individual multi-zone frac packs 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 (indiscernible). She is deepwater capable and is planned to be operational later in the third quarter.

We are also introducing new capabilities on the drilling and evaluation side. 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, anomalous high-pressure, high-temperature log.

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 three 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 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 more sophisticated solution, one that provide superior reliability and variable drawdown capability.

We successfully field tested FLEX pump in the Eagle Ford, the Bakken, the Permian 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 rodless systems and offset wells and like all ESPs without the normal tubing were caused by rod lift and 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.

With that, Trey, let's turn it over for some questions.

Trey Clark - IR: Thank you, Martin. At this point, I'll ask the operator to open the lines for your questions. To give everyone a fair chance to ask questions, we ask that you limit yourself to a single question and one related follow-up question. Lorraine, could we have the first question please?

Transcript Call Date 07/19/2013

Operator: James West, Barclays Capital.

James West - Barclays Capital: Martin, as you think about North America in the second half of the year, you obviously highlighted a lot of traction, a good traction in your pumping business in terms of utilization. We got the new ESP that you just mentioned and went through the technology there. You also got some strength in product chemicals things like that. It looks like your estimates, at least our estimates and other estimates out there have a pretty wide margin gap between yourself and some of your peers. 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 two things – I guess, one, do you think that there is a structural gap between kind of your margin potential and theirs. Two, if not how quickly do you think you can close that margin gap?

Martin Craighead - President and CEO: That's great question James. Thanks for asking it. First of all, there is 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 the improvement across the globe for us right now. So it's a locomotive that is starting to churn out and it's – it made some very nice improvement. As I highlighted two 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. That is the only issue that I believe we have in North America. We like our portfolio, 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. In that particular business, if you remember about a year ago, a little over year ago, we highlighted the issues that we were facing. One of the most critical at that time was the people utilization and action was taken and realignment made. The customer mix is pretty much where we wanted to be and the big issue there was having the right customers in the right locations and being able to get on 24 operations and that's behind us. I think the issue still lies around the – some issues around the transportation and logistics, and those are things we are 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 one to two, but I think that's behind us. So you know it's upward and onward from here.

James West - Barclays Capital: Okay. The transportation issues that you highlighted – I mean those don't seem like – I'm not trying to (putting) 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 the couple of quarter or something where you can kind of fix those issues. Is it not a fair assessment?

Martin Craighead - President and CEO: That's a fair assessment.

James West - Barclays Capital: 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 yearend, so what's the new goal now?

Martin Craighead - President and CEO: Well, I'll tell you this, this time next year I'm hoping that it starts with a seven, but we are not at 50%. 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.

Operator: Bill Herbert, Simmons & Company.

Bill Herbert - Simmons & Company: Sort of tackling the North America margin question a little bit differently. In a world in which we have relatively arranged our commodity prices and a continued positive delta between 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?

Martin Craighead - President and CEO: Well, if you also factor in, which you didn’t mention, that hopefully capital discipline that begins to permeate the service sector as much as it has 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.

Peter Ragauss - SVP and CFO: 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 I think what Martin said is easily achievable. But, again, that's going to take quite some time to get that overhang out of here.

Bill Herbert - Simmons & Company: Right. Peter, don't worry, I'm not going to go high-teens margins right away, but I hear you and that is a valid point. Martin, with regard to yearend, 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 got ongoing utilization gains domestically. Is it unreasonable to assume that North American margins by year end kind of get to somewhere approaching the low-teens?

Martin Craighead - President and CEO: 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. Remember, to follow-up on your first point, correct, 2 to 3 in Canada. 3 to 4 in Canada is obviously nowhere near as dramatic. So that's a big factor as well.

Bill Herbert - Simmons & Company: 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?

Martin Craighead - President and CEO: Ambitious is definitely correct.

Peter Ragauss - SVP and CFO: Yes, I'd probably box in a little bit more. I'd say it's ambitious to be in low-teens, it's plausible certainly to be double digits.

Bill Herbert - Simmons & Company: 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 get to kind of, after you back out the bad debt provision, something around a 1.2% or 1.3% margins for the second quarter, something like that. 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? Moreover, revenues for second half of the year in Latin America, is it reasonable just to assume that we're going to be flat – flattish with the second quarter? So help me on top line as well as for second half year in Latin America and margins for the third quarter?

Peter Ragauss - SVP and CFO: 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 in terms of revenue and, certainly, in terms of costs. So revenues ought to be up a little bit second half with new projects. 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.

Operator: Jim Wicklund, Credit Suisse.

James Wicklund - Credit Suisse: 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 has been a lot of talk about who is making up ground on industry leaders. I know you guys have lost a little bit of market share over the last year or two 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 ground 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 you are trying to lead with?

Martin Craighead - President and CEO: Jim, as you know, there is always a heavy, heavy theme of technology deployment in that part of the world. I can't say that that's changed over the last, let's say, five 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 a 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 they can hinder a divisionally oriented company like we were. I think that's probably and that's from – that's a thing that just kindly just keeps growing in terms of getting better. Okay?

James Wicklund - Credit Suisse: 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 basis in places that you might not had a couple of years ago? I would assume that that levels, the playing field on competition. Can you give us an idea of about how much, you know or percent of capital are we want to do it. We should look at over the last couple of years as kind of some cost that now should start to deliver results if you would from on an international basis?

Martin Craighead - President and CEO: Yeah, Jim, we've been spending $200 million, $300 million a year on infrastructure for the past, almost four years now. So call it $1 billion, little bit more than that, on infrastructure overall much of that was international. More recently, we built out our basis domestically and some of the oily basins for pressure pumping, but the only thing we're spending money now is a tail end of finishing up some of those projects, some of those two to three year projects. We haven't really sanctioned much new in the past 12 to 18 months. So most of that spend is behind us now.

Operator: Kurt Hallead, RBC Capital Market.

Kurt Hallead - 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 country that's around Saudi, I think there has 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.

Martin Craighead - President and CEO: I can tell you what our perspective is. 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, you know, 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 the Saudi Aramco was aiming towards, we believe, will become a reality. It's just probably six months behind.

Kurt Hallead - RBC Capital Markets: Then with respect to Iraq, what's the expectation in terms of the market dilution as the year goes on? I think you guys discussed in the past that the market dilution will continue to, say, diminish. I know you had some third-party – you've had some cost here, so how do we think about that evolution throughout the course of the year?

Martin Craighead - President and CEO: As Peter said, we're on 12 rigs now. We'll be mobilizing for three 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 pass-through revenue, it's going to be dilutive to margins, but EPS accretive.

Operator: Scott Gruber, Bernstein.

Scott Gruber - Sanford C. Bernstein: 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? Little bit on potential pass through revenues that would dilute the margins?

Martin Craighead - President and CEO: I don't want to peg the revenue stream yet, Scott, or margin projections, I will tell you that we're really happy and excited about this. It's not a big scale project, it's one drilling rig, one workover rig. The total capital commitment over couple years, its public information at least down there, so don't mind sharing, that's around between $60 million and $65 million over two years, but it's a nice infill drilling workover play. We've been very successful with (Corio) 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 two years ago, so the reservoir engineering folks, our production engineers, we've been able to really define some targets. We are drilling some horizontal wells in the (Corio) and we'll be doing that in this block, so it's a nice – it will turn into a nice service incentive contract for us, starting in Q1, Q2 next year.

Scott Gruber - Sanford C. Bernstein: Got it. Then a unrelated follow-up, earlier in the year Halliburton, and now here today Schlumberger have dedicated themselves returning more cash to shareholders. You were free cash flow positive in 2Q and your margin outlook is improving here in the second half the year what are your thoughts regarding increasing the dividend or buying back shares?

Peter Ragauss - SVP and CFO: 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 will be in a position to be able to consider shareholder distributions.

Operator: William Sanchez, Howard Weil Incorporated.

William Sanchez - Howard Weil Incorporated: I wanted to circle back on Latin America, and I appreciate the comments in Brazil that you made at the start of the call. I guess, just 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 Middle East, I believe, you said, I guess is point one. Then number two, just to follow-up on Mexico specifically. I guess my understanding prior to this call was 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, I'm just trying 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.

Martin Craighead - President and CEO: 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 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. 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 in the budgetary issues of PEMEX encountered and cut-off 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 to fall back on offshore or in the south, so the cost-cutting was necessary. But like I say, that's – and it kind of helps go to explaining the – I believe Peter mentioned this, but sharp decrementals, because there was 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.

William Sanchez - Howard Weil Incorporated: As a follow-up, unrelated follow-up. Peter, typically in Canada in 3Q you recover about one half of the lost profitability you see first to second quarter, is that a fair assumption for 3Q this year?

Peter Ragauss - SVP and CFO: There are 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 our biggest single swing factor from Q2 to Q3 is Canada and it's of sizable amount, as is typical, or maybe little bit more this time around.

William Sanchez - Howard Weil Incorporated: So, very high decrementals you have on that lost revenue in 2Q. Is getting to a 10% margin in 3Q in North America in third quarter, is that a reasonable target for you?

Martin Craighead - President and CEO: I think that's a possibility.

Operator: Michael Urban, Deutsche Bank.

Michael Urban - Deutsche Bank: You talked a little bit about the pushback of – in terms of the Saudi's plan by six 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? I guess just the obvious difference being the tightness of the market, not only in Saudi, but in some of the region, so if you could give us a little bit of color on that would be helpful.

Martin Craighead - President and CEO: 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, yeah, we push out six months and the tightness in the market is real. I don't want to speculate, because I think we all fell victim to speculating what it may do to price six 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.

Michael Urban - Deutsche Bank: Then maybe to ask you a little more broadly. 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 of that will be great.

Martin Craighead - President and CEO: 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 couple of product lines have actually increased prices, Brent, 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 of, 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 three service companies exceeded their desire, and that's a good signal. So there's some discipline coming in. But, on the other hand, Asia-Pacific, I think, has been the place where needed the most improvement. Moving north of there, outside of North Africa, there is 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 previously stated and you well know. So here it's –use that overused term, it's just a grind higher I think.

Operator: David Anderson, JPMorgan.

David Anderson - JPMorgan: Question on pricing on the North America side, how do you see that progressing right now? Here I think you had said, you started 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? I guess, I'm just kind of curious what are you guys modeling, kind of, internally as you think, I would say, the next kind of three or four quarters. Are you expecting to see pricing in terms of those numbers?

Peter Ragauss - SVP and CFO: Well, 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 were short on equipment there. But in terms of land, we're not modeling any pricing increases. Pricing is held up in our other product lines, but pressure pumping, we're not modeling any pricing increases.

David Anderson - JPMorgan: What about in the completion side? I guess I'm kind of wondering about seeing the Bakken, different areas like that. Are you getting any kind of better pricing in that side of the business?

Martin Craighead - President and CEO: It's holding up there pretty well. David, 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 of a balanced market at this point.

David Anderson - JPMorgan: I was just kind of curious, kind of overall, one of the things we are continuing to hear about is kind of pad drilling started 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 do you think that can go let's say over the next 12 months?

Martin Craighead - President and CEO: Well, I do want to tell you the percentage, but it's the amount of revenue that we earned this quarter is twice, what we earned this time last year. Not only, I 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 maybe 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.

David Anderson - JPMorgan: How does the pads impact your profitability? Let's say, we had two wells side-by-side, one set on pad, one set not on pads. Can you give me a sense of kind of order of magnitude on kind of what that does to your numbers?

Martin Craighead - President and CEO: On the pressure pumping, it's between a 30% and 50% increase in margin. Yeah, it's huge.

Operator: Judson Bailey, ISI Group.

Judson Bailey - 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 project you see coming out in either country that would help margins to get up? Or is that just simply kind of right-sizing the business for the new level of activity you have in those markets?

Martin Craighead - President and CEO: It's a little of both. We don't spend, still we've got – we've picked up some share in various places. We're expecting activity to pick up in couple of places and some new projects. So revenue will contribute to that, but above that we'll 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.

Judson Bailey - ISI Group: Then my follow-up is on the Gulf of Mexico. Obviously, the narrative there remains pretty positive, and I apologize if I missed this, but did you say how much did – can you say how much Gulf of Mexico revenue grew during the quarter sequentially?

Peter Ragauss - SVP and CFO: We don't break that out.

Judson Bailey - ISI Group: 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?

Martin Craighead - President and CEO: I think you can model in some contribution towards this end of Q4 and a full utilization into 2014.

Judson Bailey - ISI Group: Then the FLEX Pump you guys talked about on artificial lift side, can you – you outlined kind of the revenue opportunity. Could you just talk a little bit 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?

Martin Craighead - President and CEO: Well, I can tell you, it's going to start contributing to our results immediately in terms of changing North American margins one product, that's a – that (betting) can 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 can only play in about 15% of that spend. Then it takes us to about 75% of that spend. I'd tell you, this is not driven out of just wanting to put a better mouse trap 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. They don't start with an ESP, but if they know in 24 months they are going to have to put a rod lift on it, they have avoided that, some of them, 85% of them. Now we can take them down to 50 barrels a day, it gives them a whole different changes of the discussion substantially. So we're pretty excited, but please don't be changed in your numbers based on one product at this stage.

Operator: Thank you. 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 pm 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. Thank you.