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Baker Hughes Incorporated (NYSE:BHI)

Q4 2010 Earnings Call

January 25, 2011 10:00 am ET

Executives

Martin Craighead - President and Chief Operating Officer

Peter Ragauss - Chief Financial Officer and Senior Vice President

Chadwick Deaton - Executive Chairman, Chief Executive Officer and Chairman of Executive Committee

Gary Flaharty - Vice President of Investor Relations

Analysts

David Anderson - Palo Alto Investors

Kurt Hallead - RBC Capital Markets, LLC

William Herbert - Simmons

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

Robin Shoemaker - Citigroup Inc

Scott Gruber - Bernstein Research

Daniel Boyd - Goldman Sachs Group Inc.

Ole Slorer - Morgan Stanley

Operator

Good morning. My name is Thia, and I will be the conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Fourth Quarter 2010 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Gary Flaharty, Vice President of Investor Relations. Sir, you may proceed.

Gary Flaharty

:

All right, thank you, Thia. Good morning, everyone. Welcome to the Baker Hughes Fourth Quarter 2010 Earnings Conference Call. Here with me this morning are Chad Deaton, Baker Hughes' Chief Executive Officer and Chairman; Martin Craighead, President and Chief Operating Officer; and Peter Ragauss, Baker Hughes' Senior Vice President and Chief Financial Officer. Following management's comments this morning, we'll open the lines for your questions.

Reconciliation of operating profits and non-GAAP measures to GAAP results for historic periods can be found on our website at www.bakerhughes.com in the Investor Relations section under Financial Information.

Finally, I would caution you this morning that any company outlooks discussed are subject to various risk factors. We'll try to highlight these factors as we make these forward-looking statements. However, the format of the call does prevent a thorough discussion of these risk factors. For a full discussion of these factors, please refer to our annual report, 10-K, 10-Q, and in particular, the forward-looking disclosure in this morning's news release.

With that, I'll conclude our discussion of the administrative details and turn the call over to Peter Ragauss. Peter?

Peter Ragauss

:

Thanks, Gary. Good morning. This morning, we reported net income on a GAAP basis of $335 million or $0.77 per share. There are some adjustments that should be made to better compare our results to first call estimates.

First, we have incurred $56 million in acquisition-related costs this quarter. Net of taxes is $37 million or about $0.08 per share. Second, we also had a gain on investment of $6 million or $0.01 a share to another direction. So adjusting to these factors, the EPS that is more comparable to first call estimates was $0.84 per share. Revenue was $4.4 billion, up 82% or up almost $2 billion compared to a year ago and up 8% or $345 million sequentially. And EBITDA per share was $2.18, up $1.07 or 96% compared to a year ago, and up $0.54 or 33% from last quarter.

To help in your understanding of the moving pieces, I'll bridge Q4 '09 EPS to Q4 '10 EPS. GAAP EPS for Q4 '09 was $0.27 per share. Subtract a $0.01 for a gain on investment in the year-ago quarter, subtract $0.08 for the impact of the higher share count a and higher effective tax rate, subtract $0.03 for higher net interest costs, subtract $0.05 for the impact of the incremental amortization costs associated with the acquisition and add $0.02 for lower corporate expenses. Operations added $0.72 per share. That brings us to $0.84 EPS per share. Last, subtract $0.08 per share for the impact of the acquisition-related cost, and add the $0.01 gained on investment this quarter to get to the GAAP number of $0.77 per share.

Bridging the sequential quarters, GAAP EPS for Q3 2010 was $0.59 per share. Subtract the impact of the higher relative tax rate of $0.02 per share, subtract $0.03 per share for higher net interest and corporate expenses. Operations added $0.30 per share, which gets us to $0.84 per share. Again, subtract the $0.08 for the impact of acquisition-related costs and add the $0.01 of gain on investment to get to the GAAP EPS of $0.77 per share.

In Table 3 of our earnings release, we provide financial information on a pro forma combined basis with revenue and profit before tax of BJ Services, included into the prior-period's results to allow meaningful comparisons between quarters. This schedule is available on our website. From this point on in the conference call, any comments on revenue, operating profit and operating profit margin refer explicitly to Table 3.

Revenue in North America was $2.2 billion, up 69% compared to a year ago and up 10% sequentially. North America operating profits were $478 million, up $434 million year-over-year and up $138 million sequentially. North America margins were at 22%, up almost 500 basis points sequentially and delivered 68% incremental margin. We saw a strong sequential improvement in all three geo markets: Canada; U.S. land and the Gulf of Mexico.

International revenue was $1.9 billion, up 7% compared to a year ago, and up 8% compared to the prior quarter. PBT was $175 million, down $38 million year-on-year and up $80 million from the prior quarter. PBT margin was 9%, up 375 basis points sequentially, and incremental margins were 58% sequentially. Fourth quarter international results were boosted by seasonally higher than normal product sales of about $70 million.

Our Industrial Services and Other segment revenue was $281 million, up 15% compared to last year and up 1% compared to the prior quarter. Operating profit was $28 million, up $1 million compared to a year ago and down $8 million sequentially due to the seasonally lower activity in our pipeline commissioning business. PBT margin was 10%.

Turning to the balance sheet. At quarter end, our total debt was $3.9 billion or flat to the prior quarter. Our capital expenditures were $486 million this quarter, bringing the total for the year to $1.5 billion. At the end of the quarter, we have $1.7 billion of cash and short-term investments. We also have $1.7 billion undrawn and available under our committed credit facilities. Debt-to-capital ratio was 21%, our net debt was $2.2 billion and our net debt capital ratio was 13%.

Last, let me provide you with some outlook for 2011. We plan interest expense to be between $195 million and $200 million for 2011, corporate cost between $250 million and $260 million; depreciation and amortization, that will be about $1.4 billion, give or take; annual capital expenditures of $2.3 billion to $2.7 billion; and our tax rate is expected to be between 36% and 34%, higher in the beginning of the year and lower towards the end of the year.

I'll now turn the call over to Martin who will highlight our geographic results. Martin?

Martin Craighead

:

Thanks, Peter, and good morning. Let me start with North America which had an outstanding quarter across all the geo markets. The story for North America land centers on the unconventional reservoirs and the use of horizontal drilling, advanced completions and pressure pumping to access the reserves. Baker Hughes is a leader in these products and services. Beginning last September, when BJ's U.S. operations were formally merged with ours, we moved with agility to leverage the strengths of the legacy Baker Hughes product lines with the newly acquired capabilities of BJ Services.

For example, in the Bakken shale, the newly combined organization worked together to win an award. From a U.S.-independent to drilling-complete multiple wells, they're expected to have 30 fracs stages each, highlighting the continuing increase in service intensity we are experiencing. We're providing the drilling services, drill bits, fluids, wire line, completions, cementing and pressure pumping services. In the Pinedale anticline in Wyoming, we were awarded logging, stimulation, completions, perforating and pressure pumping for wells with 11 frac stages each. Further south in the Eagle Ford, we were awarded stimulation services, coil tubing and wire line services on wells being drilled by an independent that are expected to have 25 frac stages each. And in Canada, work in the primarily oil focused unconventional shale place also contributed to our North America performance.

In addition to the unconventional shales, we are also an active player in the oil sands, where we provide drilling services, completion, equipment, and of course, chemicals and artificial lift. Recently, our new ESPs have set performance records for continuous operations. In the Alberta oil sands, our extreme temperature ESP systems set a record run life in a SAGD application of more than 800 days of continuous operation in one of the harshest ESP environments imaginable. In addition, 17 centigrade ultra temperature ESP systems were installed and now have more than 2500 days of operation.

In Canada, we are also leaders in developing coalbed methane reservoirs. We recently signed an agreement with EnCana for the exclusive use of our 4 3/4 inch true track on a project encompassing 1,200 new wells over the next year and a half.

Turning to the Gulf of Mexico. Revenue and profit improved sequentially. Given the difficulty of permitting new wells in both the deep water and the shelf, operators are focusing on workovers as a way to battle production declines and workovers are an underlying strength of our Gulf of Mexico operations. Demand for the stimulation vessels has been strong and future demand for the Blue Dolphin and the Blue Tarpon is also strong. These two state-of-the-art vessels are capable of supplying 2.75 million pounds of sand each, and this is 50% more than any other Gulf of Mexico supplier.

As such, we recently signed an agreement to provide deepwater pressure pumping services for an IOC for the next four years. We've also been awarded single-trip, multi-zone frac completion systems for up to 16 wells by an NOC operating in the Gulf of Mexico. These new systems, which can reduce completion times by as much as three weeks, will be used on wells drilled in 8,000 to 9,000 feet of water to a depth of approximately 30,000 feet. And the operator's planning frac-ing these wells three to five zones each.

Last, we continue to gain share in the high-pressure, high-temperature lower tertiary segment of the shelf that we've highlighted to you in previous calls. The bottom-hole environment can exceed 450 degrees and 30,000 pounds of pressure. This is probably one of the most hostile fields being explored anywhere in the world today. So overall, our competitive position in the Gulf of Mexico has never been stronger.

Now turning to our international operations. I'm pleased to report that our international operations had a much improved quarter compared to Q3. As Peter mentioned, fourth quarter results were aided by seasonally strong products sales to export markets that were about $70 million above trend in the fourth quarter. As is the usual seasonal pattern, first quarter 2011 sales are therefore expected to be about $70 million below Q4. Last quarter, we indicated that we have taken action to reduce redundant support costs that resulted from our reorganization. We said the benefit should be visible in our fourth quarter results and they are.

Turning to Latin America. We are continuing to see strong market growth in the Andean geo market, which includes Colombia, Ecuador and Peru. This geo market continues to be a strong performer and is benefiting from a wide mix of customers and the growing diversity of our product and service sales in the region. The Southern Cone geo market consists of Argentina, Bolivia and Chile.

In Bolivia in the quarter, we have installed the first level 4 multilateral combined with an intelligent well system in the San Alberto gas field. Installed at a depth in excess of 14,000 feet, it's the deepest, highest pressure, highest temperature level 4 multilateral installed anywhere in the world. The system will allow the operator to selectively produce gas in either of two reservoir penetrations.

The Brazil geo market continues to grow as Petrobras expands its deep water drilling fleet. We expect Petrobras to add eight rigs in 2011 and another seven or eight in 2012. And IOCs, we'll add about three rigs in 2011. In the fourth quarter, we celebrated two major milestones. We now have drilled more than 2 million feet in Brazil, mostly in water depths exceeding 1,000 feet, and 1 million of that footage was drilled with the AutoTrak series of rotary steerables. In a little more than four years, we've grown from supporting two simultaneous directional drilling jobs offshore Brazil to supporting 22 today.

One of our most recent successes as well was in the fluids environmental services product line where we were recently awarded the installation of complete cuttings handling and drying systems for seven rigs scheduled to be delivered to Brazil. Once the installations are completed, the number of deepwater rigs serviced by our Fluids Environmental Services will increase to 34. Coupled with BJ's three pressure pumping vessels currently operating in Brazil, Baker Hughes is positioned in the market with a scale and a scope required to be a leading supplier for Petrobras.

Now turning to the Europe, Africa, Russia Caspian segment. The Europe region continues to deliver outstanding commercial and technical results. In the fourth quarter 2010, Europe posted the strongest increase in margins in the segment. Activity returned to normal levels in the Norway geo market, and we saw share gains in the Continental Europe geo market. Wireline completions, artificial lift and chemicals were all strong in the quarter.

We've had success introducing new technologies in the Continental Europe geo market. For example, we introduced AutoTrak V into Poland, where we are drilling two 18,000-foot exploration wells. AutoTrak V is our most advanced tool for drilling vertical wells and maintaining directional control.

Profitability improved in the Russia Caspian geo market, although we did not experience the usual year-end seasonal increase in product sales. The Russia Caspian geo market was recently awarded contracts for the giant South Yoletan field in Turkmenistan. This is an HPHT reservoir with high concentrations of H2S, making it not only one of the largest gas fields in the world, but also one of the most extreme for drilling and completion. We are providing cementing services, liner hangers, completion systems, drill bits and advanced wireline to our customer who expects to drill up to 25 wells over the next three years.

The profit margin did not improve in our Africa region. However, we do expect margin improvements as we move into the first quarter.

I'd like to turn to the Middle East, Asia Pacific segment. In the Middle East region, directional drilling, drilling fluids, artificial lift and seasonal oil field chemical sales led the sequential growth in revenue. In the Saudi Arabia, Bahrain geo market, our coil tubing integrated operations project is well underway, operating with two rigs. The project's scope includes rig in camp management, the under balanced package, all drilling services, completions and bits. And we're now packaging our Microwash remediation fluid with BJ Coil Tubing Services. The Microwash treatment cleans the screens used in the completions of a large number of wells in Saudi Arabia. And BJ Coil Tubing Services now provides a rigorous way to deliver the treatment. In some cases, production is doubled from the treated wells.

We also introduced a new product in the fourth quarter in Saudi Arabia designed to maximize production from the smaller coil tubing drilled laterals. The Ultra-Slim Equalizer has the same proven functionality as the largest sized equalizer, but can be deployed in the smaller laterals.

Last, we recently successfully completed a formation fluid sampling job from a well and some sections contains as much as 30% H2S. We used a special adaption of our reservoir characterization instrument or RCI to gather the samples in this hostile environment.

Turning to Asia Pacific. While overall activity in the region has been flat, we did see revenue growth and margin expansion in the region. Winter came a bit later to Bohai Bay which helps bolster directional drilling revenue in the quarter. The region remains very competitive. However, we see evidence in tender wins that the geo market approach is making a difference, and many of these are noted in the news release. We were awarded two drilling and evaluation services projects by IOCs conducting ultra-deep water operations in the market, as well as an award from a third IOC for ultra-HPHT drilling fluids and FES [fluid environmental services] work. The work is challenging. For example, in the Malaysia geo market, the wells to be drilled are 15,000 foot deep, and we expect bottom-hole temperatures to exceed 500 degrees Fahrenheit.

In the North Asia geo market. An IOC awarded Baker Hughes directional drilling an LWD [logging-while-drilling], bits, fishing and milling, liner hangers, drilling fluids and drilling waste management services for a major portion of a 30-well campaign. And again, our experience in sour gas reservoirs was a key determinant in the award.

Last, I want to make a few comments on our Industrial Services segment. Historically, the second and third quarters are the strongest for the pipeline commissioning and crop protection business, which are usually slower in the winter months, leading to a relatively flat Q4. Cold weather is helping sales to the refinery segment and the pipeline inspection business, and our polymers business does remain very strong.

With that, I'll turn the call back over to Chad.

Chadwick Deaton

:

All right. Thank you, Martin. Good morning, everyone. It was a very good quarter for Baker Hughes.

North America margins increased almost 500 basis points, and we had good revenue growth as the company responded to its strong unconventional shale market. International margins improved 375 basis points on strong sequential revenue growth, and clearly benefited from the emphasis on cost control and our focus on improving international margins.

Reflecting on this quarter and looking forward, first, in North America on land. Activity in the unconventional shales remain strong. Horizontal drilling which now accounts for 57% of the U.S. rig count, accounted for a little less than a third of the rig count at the peak of the last cycle only 28 months ago. In absolute numbers, it is 52% higher today than it was in September 2008.

In recent weeks, horizontal drilling has held up well. We are seeing the shift from dry gas to wetter gas and to crude oil plays. As a result, gas-directed horizontal drilling fell 4%, and oil-directed horizontal drilling increased 30%. All in all, since the end of the third quarter, horizontal drilling has increased overall 6%. And importantly, the service intensity has also continued to increase. We're seeing both longer horizontals and tighter spacing between frac stages resulting in more stages and therefore, higher demand for hydraulic fracturing.

So far, the industry has been unable to keep up. Depending on the basin, pressure pumping capacity remains tight with backlogs stable at anywhere from 90 to 180 days and therefore, supporting higher prices. Completions in directional drilling equipment and services are also in short supply and are realizing price increasing as well. The supply chain for new equipment is stretched. In fact, we question the ability of the industry to grow pressure pumping capacity faster than demand in most of the scenarios we see for 2011.

As Martin illustrated with his examples, we're performing well in this environment, leveraging our leadership in directional drilling, completions and pressure pumping. In the last couple of quarters, usually pressure pumping has pulled through perf rating completions or directional drilling. However, in some cases in this last quarter, directional drilling was pulling through pressure pumping. As upbeat as this sounds, we do have one eye on the market, and we continue to watch gas prices carefully. Overall, we expect the U.S. to average 1,740 rigs in 2011. And for Canada to average about 340 rigs. This represents a full year on full year change of plus 12% for the U.S. and flat to slightly down for Canada.

This forecast does include some growth in the Gulf of Mexico although few permits have been issued to date. Recently, the National Commission on Deepwater and Offshore Drilling made its final report. Among other changes, it is calling for a safety institute, which would be independent of the government but supported by the industry. The Department of the Interior and the DOEM on the other hand seems to be calling for more government control. Now regardless of who does the regulating, offshore operations will be more closely regulated in the future, and some things clearly stand out.

Training and certification of offshore workers have the requisite skill levels will undergo increased scrutiny. Laboratory testing will be more closely monitored with more stringent policies. Traceability and manufacturing standards for downhaul tools will increase in importance. Communications between the operator and the service company will need to improve and be well documented. And a huge market will develop for monitors and sensors like our fiber-optic completions gauges, isolation valves, reservoir monitoring and the like. We believe we're in a very good position to become recognized as a leader in offshore performance.

Turning now to our international operations. We had a good quarter there in almost every region. Latin America was led by the Andean, Brazilian geo markets. The Brazil success story really stands out when you consider where we have come from to now being one of Petrobras' leading suppliers today. Both the Venezuela and Mexico markets appear to have stabilized. However, we do not see near-term signs of either market improving materially. In Europe, Africa, Russia Caspian, our performance in Europe was strong with Norway activity levels returning to normal. We saw a steady performance in the U.K. geo market and growth in continental Europe. We are seeing the beginning of a significant interest in European shales, and we are well positioned to benefit from this trend. The Russian Caspian region should show good topline growth in 2011 after a seasonally slow first quarter. We've expanded our position in Western Siberia, and we're now well positioned to benefit from growth in Eastern Siberia as well. And lastly, we have struggled this year in Africa, but 2011 looks to be a better year.

Turning to the Middle East, Asia Pacific segment. Projects were awarded earlier in 2010, and the Middle East are now beginning and did contribute to the margin improvement in the fourth quarter and should continue to contribute as we move into 2011. In the Asia-Pacific region, we're making good progress and are slow growing in competitive region.

Looking ahead, we expect the economic recovery to continue resulting in increased oil demand and support for higher oil prices and sustained multi-year expansion of international spending. Our forecast for the international rig count is 1,180. It's an 8% increase versus last year. With the current price pace, we do not expect meaningful price leverage until late 2011.

The cost control program we began in the third quarter of 2010 resulted in real profit improvement in the fourth quarter. International profit improvement and cost control are primary areas for Baker Hughes over the next several quarters. I believe we're in a much better position to deliver on these commitments in 2011. And yes, our plans are ambitious but they're consistent with the market realities and our enhanced capabilities.

And with that, Gary, let's go ahead and take some questions.

Gary Flaharty

:

All right. Thank you, Chad. At this point, I'll ask Thia to open the lines for your questions. To give everyone a fair chance to ask a question, we ask that you do limit yourself to a single question and a related follow-up question. Thia, can we have the first question please?

Question-and-Answer Session

Operator

Yes, sir. The first question will come from Bill Herbert with Simmons & Company.

William Herbert - Simmons

:

With regard to your international outlook. Martin, if I heard you correctly, you expected that in Q1, we would see a $70 million down tick from the year-end product sales that we saw in the fourth quarter?

Martin Craighead

:

Correct.

William Herbert - Simmons

:

So I guess the question is for international Q1, x the impact of product sales, is international in Q1 higher or lower relative to Q4? And what I'm trying to discern is impact of seasonality versus project startups.

Martin Craighead

:

I don't think we really want to go into that amount of detail as compared to the international specific in Q1. But, Bill, if you go back over our history, the effects of, not only the product sales but the seasonal effects in and parts of the U.K. particularly and Russia, put pressure on international. But that all said, as you know we have some other underlying initiatives underway to try to alleviate those kind of market effects, whether it's further cost refinement, whether it's the supply chain kicking in, as well as trying to extract some more synergy out of the BJ organization in the eastern hemisphere particularly. Whatever effects we get from the market, I think we still have some tools in our toolbox to mitigate it.

William Herbert - Simmons

:

So historically, right, if you go back to 2006 when you guys started reporting or you got the geo market reporting format, your revenues are down historically 5% quarter-on-quarter and then you x out '09 and 2008 which were extreme years, you're down anywhere from, call it 1% to 7% quarter-on-quarter. So it sounds like the seasonality is likely going to outweigh project startups or we'll assume you're down in addition to the product sales. And then, Martin, with regard to the evolution of the, if you will, the roadmap for international margin improvements, supply chain initiatives, efficiencies, BJ consolidation savings and what have you, of the almost doubling in operating income in the fourth quarter internationally, how much was due to that evolution or with regard to the several different initiatives for international margin improvement?

Martin Craighead

:

You could parcel it up in a variety of ways. The things that we have under our control and some of them have to, let's say, be a little bit more market driven and some of them just take a little bit longer to materialize. And you attack what you can when you can. And I think it's fair to say that the internal cost adjustments were the predominant driver for the improvement in this particular case, in the near term of this journey that we're on. And we're probably 1/2 to 3/4 let's say through that in terms of the overhead particularly. And the supply chain, which is on the other side, the other book end to that, it kind of kicks in, in the second half of the year as we work through our inventory. Does that make sense?

William Herbert - Simmons

:

Yes it does.

Martin Craighead

:

And then in the middle of that, there's an activity mix, share attack, if you will, that plays in as well. So the front end was loaded with internal costs for sure.

William Herbert - Simmons

:

And Chad, finally for me, with regard to your outlook for U.S., it looks like you guys are prophesying, if you will, a U.S. rig count which is flat to up from current levels for 2011. And based on that and currently based upon your overall commentary with regard to service intensity, continued pricing momentum and the difficulty in putting new horsepower to work, it doesn't sound like you expect your U.S. land margins to rollover anytime this year. Is that a fair comment?

Chadwick Deaton

:

Yes, it's a fair comment, Bill. Perhaps towards the end of the year, we may see some as capacity comes in and some softness, but we continuously shift towards these oily wetter plays, and we're seeing, I mean, very little back off in terms of longer horizontals, longer extension, clients are even pushing out 8,000, 10,000 feet now. That's just involving more fracs, and when you start thinking about it, we're finally starting to see technology hit the U.S. which we've seen overseas for years and years. I mean we've been drilling 35,000 foot-extended reach wells overseas. And we just recently, completed a six and eight, 36,000 feet in Saudi, so why won't we continue to see that in the shale plays in the U.S.?

Operator

The next question will come from Ole Slorer from Morgan Stanley.

Ole Slorer - Morgan Stanley

:

Back to the BJ Services integration, glad to see that certainly the numbers that you are putting up or suggest that this integration is now going very well. Can you give us a little bit more detail over the next couple of quarters when this comes to -- I know that closing the gap on margin to your two key competitors in North America is an objective, and you have come a long way here but there's still a little bit more to go. So how much and when it comes to closing the margin gap to your two key competitors, how much of it is from fine tuning the two organizations, cross selling or leverage on some of your investments that relate to add capacities? So can you give us a little bit of a roadmap and the timing in order for you to play out?

Chadwick Deaton

:

Yes. Ole, I think our gap's fairly tight. And if you look at North America with one of our major competitors, I think we're about the same or a little bit ahead of them and slightly 100 basis points behind the other one. We've really only been able to start to integrate the North America pressure pumping with directional drilling completions, et cetera, starting in September when we actually took over. So Q1 was our first real quarter of seeing some benefit in that, and I think our margins went up in Q4, margins went up 400, 500 basis points. So I think we definitely started to see the improvement there. Q4 of North America, actually we saw a lot of the improvement coming from BHI legacy as we saw price improvement coming from directional drilling, fluids, bits, et cetera. Internationally I think is where our next big potential way will come on revenue synergies between traditional Baker Hughes and BJ. So I think we'll start seeing that in Q2, Q3 as we start seeing those revenue synergies come through.

Ole Slorer - Morgan Stanley

:

I noticed that the North Sea is traditionally one of your highest-margin businesses as well as a strong margin or strong area for BJs like it's a business as well. Could you give a little bit of a roadmap? It's your weakest margin, at least the Europe, CIS, West Africa, it's your weakest margin, what's your opportunity to take that back towards historic highs and what's the timeline given the very ambitious CapEx predictions for both the U.K. and Norway for 2011?

Chadwick Deaton

:

Well, don't let them irk the Europe, Africa Russian overall margins mask or hide the success we've had in Europe. I think we don't break those out but clearly, Europe is very strong for us. Continues to be strong and we see it strong through 2011. Now BJ, historically, is not all that strong in the U.K. or in Norway. We think this is one of our big opportunities as we are able to bring them in, in other areas but they're not big in the U.K. or Norway. This is one of the things that we were excited about when we bought them. Because if you look at their offshore sea mining capabilities in the rest of the world, it doesn't repeat in those two markets. And that of course, that obviously, takes time as these sea mining units are buried in rigs and so on. But we think that's a big opportunity for us, probably not before the second half of the year but we are seeing pull through already on coil tubing and pipeline, machine and other things in Europe. Now Continental Europe, BJ is much stronger in terms of some of the frac-ing and other things that we see on continental land Europe and eastern Europe.

Ole Slorer - Morgan Stanley

:

And so on your international margins, are you still of the view that you have your two biggest competitors as a realistic target for chasing them on margins and revenue growth?

Chadwick Deaton

:

Yes, that hasn't changed.

Operator

The next question will come from Daniel Boyd with Goldman Sachs.

Daniel Boyd - Goldman Sachs Group Inc.

:

Follow up on your expectation for margins in Africa to improve. Can you just comment on what is going to drive that? Is that a pickup in activity that you see happening or is it additional cost cutting?

Chadwick Deaton

:

Well, I think it's a combination. There's a little bit of additional cost cutting that takes place. We did quite a bit in Q4, but we haven't finished it yet which will happen in Q1. We also see an improvement coming back in North Africa. That's been pretty depressed for everybody this last year. So we see that getting a little bit stronger. We've got work to do in Angola which is an area where we've invested heavily, and has been a challenge for us. Nigeria is kind of a moderate quarter, I think, for everybody, a weaker quarter but we see Nigeria, we're well positioned in Nigeria. We think Nigeria will be a contributor for us in 2011. And in sub-Sahara Africa, we've had some good wins and good successes there in Ghana, Gabon, Uganda, picked up some several different contracts there. So I think it's just a matter of getting Africa sized to what we need and at the same time, continue to win some contracts in 2011. And getting that from a point where it's hurting us or deluding us versus contributing. So I guess that's the best way to summarize it.

Daniel Boyd - Goldman Sachs Group Inc.

:

Are all those positives enough to offset the seasonality you might see in the first quarter to maintain margins in that region or I guess, the overall geo markets?

Chadwick Deaton

:

No. There's not a lot of seasonality for West Africa or North Africa. It's not a big area where we sell huge amounts of products or sales. I think Q1 will be better for Africa than what it was in Q4.

Daniel Boyd - Goldman Sachs Group Inc.

:

I meant more of the seasonality that you see in Europe and Russia.

Chadwick Deaton

:

No.

Daniel Boyd - Goldman Sachs Group Inc.

:

And then just on the pretty ambitious CapEx program that you've thrown out there, I know part of the story with Baker is now harvesting some of the fixed-asset investments that you've made over the past few years. And then going forward to see such a big increase out of you. Can help you understand where that's going, International versus North America? But also is it in support of contracts you've already won or in anticipation of contracts to come?

Chadwick Deaton

:

Well, I think first off, keep in mind whereas last year, we didn't own a pressure pumping company. This year we do, and it is much more capital intensive. If you look at $2.3 billion to $2.7 billion that we're saying our range compared to our revenue, it's not that far off from one of our major competitors, what their revenue is, just a major pressure pumper, who just announced $3 billion. So I think a significant portion of that $2.3 billion to $2.7 billion does sit with pressure pumping and horsepower. We are playing a little bit a catch up in that area because BJ really cut back in 2008 and early 2009, on CapEx. I think they are $200 million or less in the entire year of '08. We did kick that up to some degree in 2010, and we see just an ongoing need for additional horsepower. We're no different than, I think, couple of our major competitors, we're pretty tight on horsepower sold out in North America.

Daniel Boyd - Goldman Sachs Group Inc.

:

Have you increased the cadence on pressure pumping deliverability? I think you're doing one crew every six weeks.

Chadwick Deaton

:

No. It's probably about what -- we're staying in that pace, one frac, 30,000, to 40,000 horsepower every six weeks.

Martin Craighead

:

The supply chain is still stretched. I mean that hasn't changed. So that's, I think, when Chad mentioned earlier in the comments, we've been unable to keep up. Part of that is not just our own efforts, but it's our supply chain efforts on getting the capacity through the system.

Operator

The next question will come from Kurt Hallead with RBC Capital Markets.

Kurt Hallead - RBC Capital Markets, LLC

:

Chad, when you look out at the opportunity set for 2011 and specifically focus on the international marketplace, how would you risk assess the outlook? And do you think that there's more upside to that 8% growth number on the rig count or you think there could be some -- if push came to shove more modest downside on project delays or otherwise?

Chadwick Deaton

:

Well, Kurt, I'm pretty bullish on the second half of the year. I think the second half of the year, with what we're seeing right now, the optimism of the client, the price of oil holding in, as well as it is held, a lot of projects have already been delayed. Quite a few customers talking about improving on their exploration programs, they're starting up, which they can fairly quickly. We've had some nice contract wins which will start up towards the second half of the year. So I would risk it to say I think the second half, especially Q4 could surprise us and start showing some strong growth and momentum. We talked about the price improvement, we don't really see it happening and if it happens until end of the year and that really price moves when activity really starts to move. And that's when things tighten up.

Kurt Hallead - RBC Capital Markets, LLC

:

And in that context of pricing and pricing increments going on in 2012, what geo markets do you think might be best positioned for improved pricing? And if you were the kind of handicap from a product line standpoint without magnitudes, of course, but if you -- handicap the product lines, which ones do you think have the most pricing power as you get out into latter '11 and into 2012?

Chadwick Deaton

:

Well, I read the transcripts and one of you guys asked one of our major competitors that question, and they refused to answer it because it would tell the competition. So since he didn't answer it, I don't think I'll answer it either.

Operator

The next question will come from Joe Hill with Tudor, Pickering, Holt.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

Chad, when I look at your comment that you question the ability of the industry to grow frac capacity faster than demand in most foreseeable scenarios, and you've got, I think what looks like 12% or 13% U.S. rig count growth for 2011, there's assumption in your comment that there's a certain amount of stage gain year-on-year as we do more intense frac-ing. What are you figuring that is?

Chadwick Deaton

:

Where do I figure the staging is?

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

Yes. The number of stages per well.

Chadwick Deaton

:

Well, it varies depending on the basin, but we're seeing -- Mark referred a couple of big contracts with 30. 35 is not uncommon. Some basins, there is 10 to 11. So I think we're probably at 20 to 25 stage-type fracs today. And again, this comes down to the horizontal link, the drilling. I think the average -- you could probably say horizontal drilling today extended reach is 6,000 feet on average. Clients are kicking that up to 10,000 feet. That's why they increase in stages.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

So something like 30-plus percent growth in stages year-on-year?

Chadwick Deaton

:

I see where you're coming from. I don't know the answer to that. I'd have to get back to you on that. That's a good question. It's definitely increasing. I think my comment was more back to the fact -- I think if you add everybody up, and depending on who you look at, we're talking anywhere from 4 million to 6 million additional horsepower people talking about by 2011. And the supply chain, external supply chain to us and to many others, I just don't see a way in the world that, that could possibly be delivered because we're waiting on some things now. So I don't think that's going to happen.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

Just kind of a little bit more of a detail question. The Ultra-Slim Equalizer, and this is probably for Martin, is going to allow you guys to address how many wells in the Middle East that you couldn't address before?

Martin Craighead

:

Not very many because...

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

So very few, less than 5-inch borehole.

Martin Craighead

:

We're the one drilling these coils tubing -- the majority, I think, going forward given the bottom-hole assembly that you're aware of. But you know the Equalizer made its name in the Middle East several years ago. It's just the natural evolution that now that we're drilling these type of let's call them drain holes, they're going to want the same technology, and we're the ones to run it. Joe, I want to follow up though on a comment that Chad made there. This is a tremendous business to be in right now when you think about unconventional well bore construction. The INTEQ guys, as well as their industry competitors, get up every morning trying to drill longer laterals, right? And then the BLT guys and the completions guys, again, as well as the major competitors, get up every morning trying to run longer and longer completions with tighter and tighter frac stage spacing. So back to Chad's comment about what's been done in the Middle East and some of these other places, we just don't see an end. There's probably some diminishing returns eventually in terms of length and number of stages but depending on the reservoir, we don't know where the end of this is, but we do know that we're a big participant in driving it all the way to wherever that end is. And we just don't see any stoppage at this point.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

Then finally, Chad, you said something that I thought was pretty interesting. You said that directioal was actually pulling through frac in some instances. And I was just wondering if you could give us a little more color around the improvement in the directional market relative to pressure pumping?

Chadwick Deaton

:

I think just what Martin said, the longer, more complicated horizontals and laterals are requiring better control, better geo steering and much better completions. And of course, if you're drilling through the sweet spots and being able to run the proper completion and getting in the perf fact or whatever system that you want as a completion in the whole, then that, in the sense, the clients come in to us, they're saying, "Well, this is what we want, " then, "We can turn around, it's okay. We would like the pressure pumping well." So it's just that we've just seen -- in the fourth quarter, we saw a strong demand for our directional drilling and completion services. And as a result of that, we were able to pull through BJ on some jobs.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.

:

Well, do you think in 2012, we could see pressure pumping hand the leadership baton over to directional?

Chadwick Deaton

:

I think as time goes on, with the complicated completions and drilling and everything else, you're going to be looking at a package-type program which will be much more technical in nature, much longer in reach, much more reservoir in the area of reservoir understanding and prior to drilling these wells. And I think that's the direction the clients are going to be looking to go.

Operator

The next question will come from Scott Gruber with Bernstein.

Scott Gruber - Bernstein Research

:

Well, pumping has received the majority of attention. Artificial lift sales have also been quite robust in North America. The question on the origin of the demand growth, has it all been from the traditional basins or are we actually seeing material growth out of the emerging shale plays for lift as well?

Chadwick Deaton

:

I don't know that much coming out of some of the shale plays yet. I'll let Martin answer that. I think North America, one of the big areas where we're seeing artificial lift growth and help, as Martin referred to it in his comments in Canada. Some of the SAGD and other, even in California, but these extreme high-temperature, high-pressure ESPs, it's a very, very technically challenging market 400-plus to 500 degree bottom-hole temperature. So when you can start getting tools down there then get an 800-day run light, and this is what ESPs are all about, not having to pull these things. Martin, do you know anything about the shale play in ESPs?

Martin Craighead

:

It's a bit of a -- there's definitely a de-watering element in this side, but there's a -- what do they call it, kind of a rediscovery of the Permian because of where oil prices are, and that's a big, big, big market for our ESPs. And then don't forget the Gulf either. Aside what's happening on the permitting/drilling side as our customer want to get the production back up, we're seeing quite a bit of artificial lift there. So it's really a liquids driven, and there is an element of traditional oil as well as, let's just say, water management on some of the gas side of the business.

Scott Gruber - Bernstein Research

:

And I know you're reluctant to talk price on a product line level. But is pricing in lift approaching the 2008 peak?

Chadwick Deaton

:

I don't think that's pricing on ESPs has never have really been hit that hard through the downturn. And if you look at our -- this is one thing in our production side of the business, chemicals and ESPs, we saw some softening but not anything like what we saw in bits and directional drilling and pressure pumping and everything else during that downturn. So I would have to say it's fairly close to where we were in 2008.

Operator

The next question will come from David Anderson with JPMorgan.

David Anderson - Palo Alto Investors

:

I just want to go back on the CapEx question. You talked in the past about realigning your manufacturing operations to get closer to the customer. And just kind of curious on where do you stand right now on that? And is part of this CapEx budget going towards building out more manufacturing in Eastern Hemisphere? Halliburton was talking about that a bit yesterday. I was just wondering if you're planning to do the same.

Martin Craighead

:

Yes, we are, and part of that is international manufacturing roofline.

David Anderson - Palo Alto Investors

:

So if we think about that kind of realignment manufacturing, can you just kind of give us a sense as to how far along you are in that process? Are you where you want to be now? Are you a couple of years away?

Chadwick Deaton

:

We're on our schedule. We're happy with where we are, but I'm not so sure if you ever really end in it. Though I expect that it's a pretty sizable portion of new, let's say, capacity will be built internationally relative to where we closed this year, and the answer is yes.

David Anderson - Palo Alto Investors

:

Just shifting over to North America. One of the things I'm starting to hear about is our cost inflation. And particularly, sand and propanes. Just wondering if that's a concern that could impact your margins a few quarters down the road? Presumably, you can increase pricing to match inflation, but I guess do you have enough sand kind of lined up to meet your existing and new capacity going forward?

Chadwick Deaton

:

Well, sand is always, in these times, sand and propanes always become a challenge. Water is a challenge right now. We're able in this market, if we do get that price increase from our suppliers, we're able to pass that on. And if the market should soften and we go down and we go back to our suppliers, they cut back on their pricing to us. So I think right now there is a little bit of inflation taking place, but we're able to handle it.

David Anderson - Palo Alto Investors

:

And with all the talk about the capacity coming on, I know there's concerns about too much capacity is going to crush price. But is it possible that some of this, I guess, supply bottlenecks could support that capacity coming on in your opinion?

Chadwick Deaton

:

Absolutely. I think it's not only just propanes and guars but it's the engines, the fluid ends, the power ends, transmissions, chassis, you start adding 4 million horsepower, that supply-chain becomes tight. And a lot of those suppliers will look to who's been in business a long time, who's going to be in business a long time and they prefer to make sure they're providing those components to those people. So we like the position we're in from that standpoint. Due to volume, we get better pricing from our suppliers, and we also commit to some things. There's enough room out there that if we see a downturn, we're able to go ahead and adjust. And we've got about a six-month window there that we're committed to, and we watch it quarter-by-quarter. So at the end of the first quarter, if we see something changing, we can adjust which will affect Q4.

David Anderson - Palo Alto Investors

:

In Mexico, BJ had a bunch of pressure pumping equipment done in Mexico. Has that all been reallocated to the States?

Chadwick Deaton

:

No, not all of it. There's still capability there.

Operator

The next question will come from Robin Shoemaker with Citi.

Robin Shoemaker - Citigroup Inc

:

Just a clarification on the range of CapEx of your guidance. Is that a function of how much pressure pumping capacity you actually add at the high end or low end? Or is that the swing factor?

Chadwick Deaton

:

Yes, that's the swing factors. As I just was mentioning, Robin, $2.3 billion to $2.7 billion, and we will watch that as the quarters unfold. So that would be the swing level. And part of it too is how much can we actually deliver on that, because we're just like I said, everybody else. We've got a significant growth in CapEx and can we deliver all of it to the field.

Robin Shoemaker - Citigroup Inc

:

And so if the market were to significantly slow, how quickly could you put the brakes on this capacity expansion of every six weeks you're adding a new frac spread?

Chadwick Deaton

:

Well, as I said you're looking at about a six-month window in there. So some components maybe it's four months, some components, it's six months. And that's not just for pressure pumping. We see that in the directional drilling, wire line tools, et cetera. So I think your four- to six-month commitment timeframe.

Robin Shoemaker - Citigroup Inc

:

And then finally, in terms of your preference or strategy with regard to putting your pressure pumping capacity under long-term contracts versus maintaining some at more spot rates or giving you the flexibility to push pricing on a short-term basis, do you have any preference in terms of allocation of your capacity in that respect?

Chadwick Deaton

:

Well, we like the flexibility. We like some long term, and we've got a big one in the Bakken that's five years. It ties up 85% of their DD, LWD bits, et cetera. And I think about 35%, 40% of pressure pumping. That's a five-year type contract. We've got quite a few two-, three-, four-, five-month type commitments to clients. We've recently had some discussions with some major or some fairly large independent clients regarding a much longer-term relationship to work on the total package, whether are we going back to in terms of the reservoir, the drilling, the completion, the frac-ing, the overall picture and looking into longer-term relationships. So we like this mix package to be a little flexible.

Robin Shoemaker - Citigroup Inc

:

And when you do experience cost pressures, either labor or materials, freight, whatever, are you able to push those through fairly quickly with whether it's term or a spot rate?

Chadwick Deaton

:

Yes. In the U.S., you can push them through fairly quickly compared to others with international, which is much longer-term contracts.

Chadwick Deaton

:

Thank you. I wanted to thank Chad, Martin, Peter, everyone, all of our participants this morning for your time and your thoughtful questions. Following the conclusion of today's call, both Alexey and I will be available to answer any additional questions you may have. So once again, thank you for your participation. Thia?

Operator

:

Thank you for participating in today's Baker Hughes Incorporated conference call. This call will be available for replay beginning at 1:00 p.m. Eastern, 12:00 p.m. Central time, and will be available through 10:00 p.m. Eastern time on Tuesday, February 8, 2011. The conference ID number for the replay is 35151016. The dial-in number for the replay is 800-642-1687 in the U.S. or (706)645-9291, international. You may now disconnect.

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