Trey Clark - VP, IR Martin Craighead - Chairman & CEO Peter Ragauss - SVP & CFO.

Jim Wicklund - Credit Suisse Angie Sedita – UBS Byron Pope - Tudor, Pickering James West - ISI Group Kurt Hallead - RBC Capital Marshall Adkins - Raymond James Ole Slorer - Morgan Stanley Rob MacKenzie - Iberia Capital.

Hello. My name is Lorraine, and I will be your conference facilitator. At this time, I would like to welcome everyone to the Baker Hughes Third Quarter 2014 Earnings Conference Call. (Operator Instructions) After the speakers’ remarks, there will be a question-and-answer period. (Operator Instructions) I will now turn the conference over to Mr.

Trey Clark, Vice President of Investor Relations. Sir, you may proceed..

Thank you, Lorraine. Good morning, everyone, and welcome to the Baker Hughes third-quarter 2014 earnings conference call. Here with me today is our Chairman and CEO, Martin Craighead; and Peter Ragauss, Senior Vice President and Chief Financial Officer.

Today’s presentation and the earnings release that was issued earlier today can be found on our website at bakerhughes.com. As a reminder, 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 advise you to review our SEC filings for a discussion of some of the factors that could cause actual results to differ materially.

Also, a reconciliation of operating profit and other non-GAAP measures to GAAP results can be found on our earnings release and on our website at bakerhughes.com under the Investor Relations section. And with that, I’ll turn the call over to Martin Craighead.

Martin?.

Thanks, Trey, and good morning. This quarter we delivered a number of positive milestones, including record revenue, record EBITDA, and record free cash flow. Yet as the quarter unfolded, market dynamics began to shift causing margins in several of our operating segments to diverge from our expectations.

This included region-specific trends that required immediate action and some evolving macro themes emerging for the coming year. Among the challenges this quarter were several geopolitical events across international operations.

Disruptions in Libya and Iraq and a shortfall in the Russian ruble pressured our revenue and margins in the Eastern Hemisphere. And in the Gulf of Mexico, profitability dropped sharply due to a significant number of deepwater rigs that were shut down waiting on unusually strong ocean currents to subside.

Among the positive trends emerging, our Latin America segment is delivering profitable growth. Recent wins in markets where technology is valued, such as offshore Mexico and Brazil, are resulting in revenue growth and margin expansion.

And within our United States onshore business, the recent increase in activity and service intensity per well has caused strong demand for pressure pumping services and rapid tightening across the market.

The trend of more horizontal drilling, longer laterals, more stages per well, and more profit per stage has soaked up the remaining spare capacity in the market.

These market forces, along with actions we have taken to transform our pressure pumping business, have set the stage for robust growth in our North America segment accompanied by solid increase in margins for the fourth quarter.

In the end, although the sequential results remain positive, including a 5% increase in revenue and more than a 10% growth in adjusted net income, the quarter fell short of our expectations.

I want to highlight a few of the actions we have recently taken to mitigate some of the industry challenges going forward and to increase earnings in the short term.

In North Africa, in response to the industry-wide disruptions experienced in onshore Libya, we have consolidated several operations and restructured our geomarket to streamline our business and improve efficiencies. These savings will be realized in our Europe/Africa/Russia Caspian segment beginning in the fourth quarter.

In Iraq, where the industry has also seen disruptions, we completed the demobilization of a large turnkey contract during the third quarter. This action will contribute to increased profitability in our Middle East/Asia Pacific segment in the fourth quarter.

In Venezuela, we’ve employed an alternative business model to support and partner with local providers. Through this unique approach, we continue to enable energy production in this critically important country while simultaneously improving profitability.

These are examples of actions we have taken which will deliver increased margins in each of our international segments, including the resumption of growth in the Eastern Hemisphere next quarter. That brings me to North America where our number one priority has been and continues to be increasing margins.

The lack of margin expansion in the third quarter is mainly attributed to a sharp decline in our Gulf of Mexico geomarket.

This operation, which is one of our most profitable businesses in the world, experienced a significant drop in deepwater activity as a result of abnormally strong ocean currents, which caused several key customers to suspend operations.

In total, 13 different deepwater rigs were delayed at some point in time during the quarter causing a significant decline in well construction activity. The loss of this high-quality revenue impacted our North American margins by approximately 150 basis points.

At the same time, in our onshore operations, we were very pleased with the tremendous growth in our pressure pumping business. This one product line grew almost 25% in one quarter and accounted for 75% of the sequential revenue increase in North America.

The earnings contribution from this growth more than offset the lost operating profit in the Gulf of Mexico. Although pressure pumping margins did increase sequentially, due to rising input costs that we were not able to recoup until later in the quarter, incremental margins were not as strong as we expected.

With better commercial terms now in place, our pressure pumping business today is substantially stronger than it was only three months ago. Efficiency is better, utilization is high, and new pricing has now taken hold. Outside of pressure pumping, our other product lines are performing very well.

Newly introduced well construction and production technologies are seeing strong demand and our new product introduction metric is on pace to be the highest it’s ever been. Our outlook for the short term remains positive and I’m confident we will deliver strong earnings growth and free cash flow in the fourth quarter.

As we look beyond the short term, we see a number of evolving macro themes which are shaping our outlook and strategic plans for the coming year.

Later in the call, I’ll provide more detail on the themes we are seeing emerge and why I’m confident that our strategy, technology portfolio and investment position will allow us to navigate these market conditions. But first, let me turn it over to Peter for additional details on the quarter and our guidance on the near term.

Peter?.

Thanks Martin, and good morning. Today we reported adjusted net income for the third quarter of $447 million or $1.02 per share. Adjusted net income excludes $14 million in before and after-tax charges or $0.03 per share relating to the impairment of a technology-related investment.

Adjusted net income also excludes $58 million in before and after-tax charges or $0.13 per share associated with business restructuring of our North African geomarket, resulting primarily from the recent disruption of onshore operations in Libya.

This charge includes reserves for doubtful accounts, inventories, and certain other assets, along with severance costs. Concurrent with the restructuring of this business, certain North African entities previously reported in our Middle East/Asia Pacific segment are now reported within our Europe/Africa/Russia Caspian business.

Likewise, the historical financial results of these two segments have been revised to reflect this change. Compared to the previous quarter, adjusted earnings per share increased $0.10 or 11%. On a GAAP basis, net income attributable to Baker Hughes for the third quarter was $375 million or $0.86 per share.

Revenue for the third quarter was $6.25 billion, a record for Baker Hughes, and an increase of $315 million or 5% compared to the second quarter. Adjusted EBITDA for the third quarter was also a record for Baker Hughes at $1.19 billion, up $29 million or 3% sequentially.

To help in your understanding of the quarter’s results, I’ll bridge last quarter’s earnings per share to this quarter. In the second quarter of 2014, we posted GAAP net income of $0.80 per share. First, add back $0.12 for litigation settlements and the Venezuela currency devaluation, which were highlighted in the first quarter.

That brings us to a second quarter adjusted EPS of $0.92. Moving to the third quarter, add $0.06 for North America operations due to increased U.S. onshore activity and the seasonal increase in our Canadian business, both of which were significantly offset by reduced deepwater activity in the Gulf of Mexico.

Subtract $0.04 for international operations due to reduced profitability primarily in our Eastern Hemisphere segments, which was partially offset by increased profitability in Latin America. Next, add $0.05 for a reduction in corporate costs and non-controlling interest and add $0.03 for a lower tax rate.

That brings us to adjusted earnings per share of $1.02 this quarter. To get to GAAP earnings per share of $0.86, subtract $0.16 for the technology investment impairment and for the business restructuring in North Africa.

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, which excludes these adjusting items.

Taking a closer look at our results from operations, we posted record revenue in North America of $3.16 billion, up $312 million or 11% sequentially. North America operating profit was $380 million, up $40 million sequentially. As a result, our North America operating profit margin was 12%.

The lower incremental margins are attributed primarily to poor mix. Essentially, lower margin revenue growth from pressure pumping was partially offset by reduced high-quality revenue in the Gulf of Mexico. Moving to international results, we posted revenue of $2.76 billion, which is flat versus the prior quarter.

Operating profit was $375 million, a decrease of $29 million versus the prior quarter. Revenue in our Europe/Africa/Russia Caspian segment was essentially flat compared to the second quarter. Margins declined 310 basis points due largely to unfavorable exchange rates, which impacted profitability by approximately 200 basis points.

This includes a 15% drop in the value of the Russian ruble. Margins were further impacted by unfavorable mix in Africa late in the quarter, which more than offset increased business in Europe. Our Middle East/Asia Pacific segment saw a slight drop in revenue during the quarter.

This is partially attributed to reduced revenue in Iraq where we demobilized on a major contract during the quarter. Additionally, planned product sales in Asia were lower than expected. In Latin America, revenue increased 5% and operating profit margins improved by 180 basis points.

We achieved growth in Mexico and Argentina and within our pressure pumping and completion systems product lines. This growth was partially offset by significantly reduced revenue in Venezuela, reflecting the adoption of SICAD II late last quarter. For our industrial services segment, we posted revenue of $333 million, which is flat sequentially.

Operating profit margins were 10.5%, up 30 basis points over the prior quarter. Looking at the cash flow statement and balance sheet, during the quarter, we generated $725 million in free cash flow, a record for Baker Hughes. We ended the quarter with a cash balance of $1.2 billion, which is unchanged from the prior quarter.

Total debt for the quarter declined by $144 million or 3% sequentially to $4.4 billion and we ended the quarter with a debt to capital ratio of 19%. Capital expenditures for the quarter were $425 million. During the quarter, we repurchased approximately 2.9 million shares on the open market, totaling $200 million.

This leaves just over $1 billion remaining under our previously announced authorization to repurchase shares. Also, during the quarter, as previously announced, we acquired a pipeline of Specialty Services Business for $246 million in cash.

Now, let me provide you with our guidance for the fourth quarter, beginning with our North American business, we project the U.S. onshore well count will continue to modestly increase into the fourth quarter as we expect the holiday period slowdown to be less pronounced than prior years.

In Canada, the average rig count is projected to increase about 10% sequentially, and in the Gulf of Mexico, we expect activity to return to normal levels and to include a backlog of well construction projects.

In summary, for the fourth quarter, we expect North American market conditions to be favorable, resulting in a healthy increase in revenue and margins sequentially.

Turning to Latin America, revenue and margins are both expected to rise based on year-end product sales, increased activity in offshore Mexico and a new favorable contract for drilling services in Brazil, which is expected to start in December. Our Middle East/Asia Pacific segment should also benefit from year-end product sales.

Additionally, with the demobilization in Iraq behind us, profitability in this country is expected to contribute to increased margins across this segment. In Europe/Africa/Russia Caspian, we expect higher activity in year-end product sales in Africa. This growth is expected to be partially offset by reduced activity and profitability in Russia.

As a result, revenue and margins are expected to be up slightly for the fourth quarter. In summary, across each of our oilfield segments, we expect to see an increase in revenue and margins to end the year. For our industrial services segment, revenue should increase about 5% sequentially.

This includes our recently acquired Pipeline and Specialty Services Business, which is partially offset by seasonality in our existing process and pipeline and services business. Margins should be in line with the third quarter. With respect to non-operational items, corporate costs are expected to be between $65 million and $70 million.

Interest expense is expected to be approximately $60 million. The fourth quarter effective tax rate should be similar to the third quarter adjusted tax rate or about 35%, and finally, capital expenditures should be around $500 million. At this point, I will now turn the call back over to Martin.

Martin?.

Thanks, Peter. As I mentioned in my opening remarks, our industry is seeing a number of evolving dynamics, the most obvious being the recent slide in oil prices.

If oil remains at these levels for a sustained period of time, it will clearly have an impact on our customers in the form of reduced cash flow, and accordingly, less funds available for capital expenditures.

In the near term, we could see customers curtail activity, especially those who are more sensitive to commodity prices, while pursuing marginal onshore and shallow water plays.

But for national oil companies and deepwater customers, two areas where Baker Hughes is in a very strong position, we do not expect to see a meaningful change in activity any time soon. And if lower commodity prices continue to drag on, we may also see divergence between international and North American markets.

Historically, when commodity prices soften, North America activity levels are the first to adjust, but today, the combination of a stable business environment and more predictable production from the unconventional, has made North American activity more resilient.

With current breakeven prices for most basins in the $60 to $70 per barrel range, we do not expect to see a meaningful pullback in North American activity in the near term.

Although our customers are still in the process of refining their 2015 budgets, at this time from what we are hearing from them, we continue to project increased well counts and increased spending per well. In addition to fluctuating commodity prices, our industry is encountering a steady stream of complex geopolitical issues.

As an example, Baker Hughes has made a number of long-term strategic investments in Russia, including manufacturing facilities, a world-class technology centre and a strong local workforce. Russia has been a source of profitable growth for Baker Hughes and today contributes about 2.5% percent of our revenue. The U.S.

and EU sanctions and subsequent drop in the ruble will obviously reduce growth opportunities going forward. So within the context of these market dynamics, I want to provide more detail on my continuing conference in the near-term outlook for Baker Hughes. Starting with North America, we are on a path to deliver meaningful revenue and margin growth.

Our strategy to transform our pressure pumping business is hitting all its metrics. Here are the three main reasons why we project profitability to increase significantly for this product line in the fourth quarter and into next year. First, better utilization.

We entered the third quarter with a handful of fleets that were idled, and today, we are essentially fully utilized with no idle equipment remaining. This will result in higher utilization and better absorption in the fourth quarter. Second, increased stage counts. The trend of more horizontal wells, longer laterals and higher stage density continues.

Additionally, the transition of our fleets to 24-hour operations is ahead of schedule, and today, 70% of our fleets are operating around the clock and we expect this figure to increase by the end of the quarter. Based on higher utilization rates and more 24-hour operations, we are on a pace to complete the highest stage counts since early last year.

And third, and most importantly, higher revenue per stage. Tightening market conditions have allowed us to be more selective with the customers we work for. Just as we secured more 24-hour operations, we’ve also secured contracts with better pricing.

More than half of our business today is performed under new commercial terms, which were secured just in the last couple of months, and we’re now seeing the full benefit of this turnaround today.

In addition to the accelerated transformation of our customer base, we’re also benefiting from incremental cost reductions resulting from actions we have recently made to reduce maintenance costs and optimize our supply chain.

These actions are helping us handle the rising logistical challenges associated with the increased activity levels and volumes of raw materials per well. Across our other product lines, newly introduced technologies designed to improve well efficiency and optimize production are well embedded in the market.

To give you just a couple of examples, our customers have used AutoTrak Curve to drill more than 15 million feet in North America so far. That’s a remarkable milestone for a product only three years into its life cycle and underscores the value of a technology that is redefining the technical limits of drilling in the unconventionals.

On one project for a major operator in the Marcellus this quarter, we drilled more than 7,300 feet of lateral section in a 24-hour period. That’s a record for us in North America and something that used to take four or five days before the AutoTrak Curve was launched. And the other obvious example is our FLEXPump artificial lift technology.

We introduced FLEXPump on an earnings call last summer. This technology is helping our customers to reduce lifting costs and boost IPs. In a little more than a year, we already have about 4,000 FLEXPump systems in the ground.

For our customers, products like these are no longer novelties, but are now necessities, and when our customers are searching for ways to cut cost and boost production, only technology can provide a real step change in performance and our differentiating value for Baker Hughes. Internationally, we are pleased with our current position.

We expect to benefit from a pair of key market segments which tend to be less impacted by short-term oil price fluctuations. First is the deepwater market. Based on lengthy planning cycles and long production horizons, these projects are not likely to see a material impact in the near term based on today’s oil prices.

During the last year, Baker Hughes has targeted and secured a series of long-term contracts for well construction services in many of the world’s most active and technically-challenging deepwater markets.

In West Africa, we have secured several multi-year contracts to provide drilling services, cementing, fishing, wireline and production chemicals for a number of deepwater clients. These contracts begin to take hold in the fourth quarter.

In Norway, a previously announced contract to provide completion systems to Statoil begins in the first quarter of 2015. In Deepwater Australia, contracts for wireline services and drilling services have been awarded and are now being executed.

And in Brazil, new contracts with more favorable terms for stimulation, drilling and wireline services will contribute to profitable growth in both the near and longer term. The addition of these deepwater contracts is well timed and will provide an outstanding source of activity going forward. Next, many of our customers are national oil companies.

With aggressive production targets for both oil and natural gas, these companies have been the engine of growth in the Eastern Hemisphere this year and likely for years to come. Over the last five years, Baker Hughes has made a number of strategic investments to increase our local content and strengthen our alignment to the NOCs.

This includes the geographic alignment of our management, the construction of multiple world-class facilities, the creation of a global network of R&D centers, and the hiring and development of local workforces.

The exceptional growth of our Middle East /Asia Pacific segment over the last two years is a reflection of this strategy in motion and is expected to provide continued growth opportunities going forward.

To summarize, I’m confident that Baker Hughes is on pace to deliver solid results in the fourth quarter, and although we expect to see some market readjustment in 2015, we are well positioned for the months ahead. National oil companies are expected to remain an engine of growth. Deepwater projects are currently moving forward.

And in North America, customer spending should remain stable at today’s commodity prices. But the most important long-term trend for Baker Hughes, the element of our strategy that transcends market conditions, is anticipating our customers’ ever-increasing reliance on innovative technologies that enable the safe, affordable production of energy.

Against this backdrop, I’m confident the execution of our strategy will continue to deliver differential earnings, increasing returns, and strong free cash flow. Now, before we turn it over for Q&A, I would like to take a moment to thank Peter as he concludes his last earnings call before retiring from Baker Hughes.

When Peter arrived as CFO nine years ago, our revenue was a third of the size it is today. We were a collection of seven divisions and each with a different financial and management reporting system.

Under Peter’s leadership, our financial organization has been transformed as our systems and processes have been standardized and streamlined and made far more efficient across the entire enterprise. So, on behalf of the entire leadership team and our Board, we thank you Peter for your service and we wish you the very best of luck going forward..

Thanks, Martin. That’s very kind..

Okay. So with that Trey, let’s open it up for some Q&A..

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.

Can we have the first question please?.

(Operator Instructions) And our first question comes from Jim Wicklund from Credit Suisse. Please go ahead..

Martin, do you still think that you can reach 15% margins for North America by the end of the year?.

Absolutely, Jim, I’m confident that we will. It’s not going to be a walk in the park. The Gulf of Mexico issue with the currents were certainly not expected in the third quarter.

We’ve never seen them as strong and the duration of them has, as far as I can tell is unprecedented, and going into Q4 we need some help there, if you will, from Mother Nature that the Gulf comes back.

I think the thing to keep in mind, Jim, is that those, particularly the Mississippi Canyon completions, that were delayed and some of the drilling activity has not been canceled, it’s simply backlogged into the fourth quarter.

So if we’re going to have an extremely robust, almost maniac level of activity, and then you have the backdrop of the pressure pumping market, wells aren’t getting shorter and stage density is not getting less, and our customers aren’t not going to pump less sand per stage. We were up 22% or so sequentially in pumps per stage.

That’s going to continue, maybe slow down a bit. So that plus the continued absorption of new technology, I don’t want to say that it’s going to be easy, it’s not, nothing yes, but I’m very confident that we’ll deliver on that number..

Maniac levels of activity is always nice to hear, as long as I’m not the one who has to manage them. So that’s good..

It goes for me too..

And Latin America, both Brazil and Mexico, we all know they’re going to recover. You’ve got the – you won the drilling contract in Brazil and Mexico is getting better.

Can you just discuss a little bit the potential magnitude, because I think we’re probably going to need help from Latin America in 2015? Can you talk about kind of the magnitude of what you expect to see there over the next year?.

That’s a good point when you say a good help – some help because I agree with you. The first thing I’d say is we’re not projecting a lot of activity in the market growth in ‘15 for Mexico, and our successes so far, and I credit our team, have been some pretty substantial share gains offshore on the drilling and completion side.

I think that will continue, and then our projects up in the North have been quite well received both by PEMEX and in terms of the bottom line. So Mexico is looking good, but I wouldn’t say market-wise, we are going to see a lot of help.

And in Brazil, you’re right in referencing the share gain on the drilling contract, but internally the drilling contract, it’s been recast, if you will. We maintain a large stimulation vessel position. That’s been recast. Certainly, the wireline tender has been tendered and announced, but again the commercial terms are more supportive.

But in neither of those, do we expect them to touch Q4. It will be more of a Q1 activity boost for us, and then again the commercial terms are more attractive.

But I’d say Brazil, through the end of ‘15 and certainly into ’16, the discussions we’re having with our clients there is that they are going to reinvigorate on the exploration side far more than they have been over the last couple of years [technical difficulty]..

Okay. Martin, thank you very much. Peter, all the best. I still think we need to build that hotel though out by Baker’s R&D facilities..

I’m in..

Thank you. And our next question comes from Angie Sedita from UBS. Please go ahead..

Martin, going to your comments in the prepared remarks, you said that you currently have no idle equipment in pressure pumping in North America, and then your comments on the commercial terms.

First, on the idle equipment, does that imply that you've unstacked all of your cold stacked equipment, or just what's in the field is all up and operating? And then, on the commercial terms, have you had any success in net price gains or more cost recovery driven?.

That’s a good question, Angie.

I would say that we have no -- we activated a fleet in the third quarter and we have no hot-stacked equipment left, and pretty much this quarter we’ll empty any of the cold stack, okay? So there is nothing that can be put back into operations that won’t be a newbuild certainly by the end of this fourth quarter, and could you repeat your pricing question, you cut out on --?.

Yes, on the commercial terms, was it cost recovery -- you are increasing pricing on the pressure pumping side, so was that cost recovery only, or were you able to see any net increases in prices?.

We saw a net increase in pricing in the last few weeks of the last month.

We saw quite a bit of cost inflation first led by freight, followed by sand, and the difference between three and four in that business and it gets a little bit back to Jim’s question, about 70% of our business is contracted, about 70% of those contracts now have indexed pricing adjustments.

So I expect that in Q4 we’re actually going to see a little bit of flattening on the inflation that occurred in Q3 and the pricing lift above those costs will be far more material for that business line in four versus three, Angie..

Okay. That's extremely helpful.

And then, just as an unrelated follow-up, do you have any early thoughts, given the changing dynamics, both in North America and even to some degree globally, Asia, Russia, on revenue growth rates for 2015, when you think about North America versus LatAm versus Eastern Hemisphere, even directionally from your original expectations?.

That’s a great and very broad question. Let me try to answer it this way.

As you well know and most of the people on this – that are listening, our customers, right now, are in the throes of trying to determine what their budgets are going to be for ’15, but I can tell you the channel checks I do with my peer customers are that they are concerned with what’s going on in the oil markets, but they are not, at this stage, I think frankly because we’re all a bit surprised with the markets, are they willing to give it a whole lot of credibility either that these numbers are what we’re going to see in terms of commodity prices.

So they are still confident that, I think at this stage, these oil prices are not where they’re going to settle and also -- let’s also realize that, as you’ve written about and your peers, the breakeven prices in most of these basins with most of the customers are still well below what the commodity prices are.

So I don’t expect that we’re going to see any appreciable activity decline, but if oil should stay at this level for a couple of quarters and give it, so to speak, more credibility that this is what the environment is going to be, then certainly a few of the customers out there that are either more dependent on borrowing or maybe have a less attractive subsurface position, could sideline, but I don’t see that being material for us or, like I said, I’m not projecting that any time soon.

Internationally I can’t predict nor can I control some of the issues that are going on geopolitically. Certainly, as you know Angie, we’ve talked about Russia has been a great growth engine for us. That’s not going to be there for a while. We are hopeful. We’re monitoring it and we are watching it very closely.

And for the Middle East, some slippage in Iraq is going to be more than offset by strength in the rest of the Gulf led by Saudi. So I’m bullish on [indiscernible] and EMEA led by the Middle East, and as we talked about on the previous question, Latin America could be a bright spot from an international perspective..

Perfect. Thank you for all the color, and Peter, I also wish you the best on your retirement. Thanks again, Martin..

Thanks a lot, Angie..

Thank you. And our next question comes from Byron Pope - Tudor, Pickering. Please go ahead..

Martin, when I think about the benefits of you guys having reorganized your North America region by geomarkets almost a year ago, I guess it would seem as though you guys are pushing toward being better aligned with the types of E&P operators that see the value of your service – value combination.

So I guess my question is, how far along are you in terms of having migrated your North America customer base to those sorts of the E&P operators?.

I’d say we’re probably – it’s been a year now, probably 75% would be a rough estimate depending on how you characterize that. I guess that’s certainly has always been that way in the Gulf of Mexico, but on North America land, I’d say probably about 75%, Byron..

And then, just a follow-on question. Based on what you’ve seen in past cycles, obviously no one really has a good view at this point on how North America activity progresses over the next 12 months.

But when I think about Baker technologies like FLEXPump, ProductionWave, SHADOW series frac plugs, it seemed as though the customer adoption rates should prove fairly healthy, barring some game over scenario, on the commodity price front.

But I’m just curious as to what you tend to think historically as it relates to new technology adoption by customers? When activity perhaps slows, growth rates potentially slow a little bit overall..

That’s a very good question.

Here is the – as I said in my prepared remarks, we’re all going to be in a much better position as far as North America is concerned no matter what the global scenario is, because the unconventionals provide a far better level of predictability for our customer both in terms of costs per well, which are going down because we’re more into this industrialization, if you will, and the geological risk of these wells is less than what it’s been for previous -- through previous cycles.

So, North America Land plan will certainly be a lot more resilient.

Now, maybe a little bit to your first part of your question, as these customers perhaps let’s say get a little bit more scrutinizing on ultimate recovery figures and initial flow rates, then there is an emerging group of technologies within our organization that are aimed right at the unconventional, right? So, you don’t want to be drilling with a conventional motor bottom hole assembly when your peer is drilling on the adjoining lease with AutoTrak Curve because you’re going to get your tail kicked.

And I don’t think they’re going to want to be in a position, that’s why I say things like AutoTrak Curve and FLEXPump and ProductionWave are not novelties, they are changing the conversation with the customer and we don’t ever want to see a tightening price or cost environment, but on the other hand, they will be more front and centre with our customers as their budgets perhaps become a little bit more strained.

So, I feel great about our portfolio as it relates to the customer situation. The second thing is, Byron and you know this, it may go more to an OpEx world than a CapEx world for our customers. Again, there is ProductionWave, there is Upstream Chemicals right at the heart of maximizing production and cash flow for our customers.

So, I’m realistic about what’s going on, but I’m also extremely excited about the way we sit in terms of being able to solve some of these problems..

That’s helpful, Martin. I appreciate it, and Peter wish you the best..

Thanks, Byron..

Thank you. And our next question comes from James West from ISI Group. Please go ahead..

So, Martin, would you say that as we look into 2015 that your growth outlook versus say your peer group is differentiated given your market share gains and contract wins in North Sea, Brazil, parts of West Africa, is that a fair statement?.

That’s a very fair statement.

Sometimes what do they say, better to be lucky than smart? Six months ago we didn’t see this, what we’re experiencing today, and six months from now it can be a whole lot different, but six months ago, a year ago, we pick up one of the world’s largest drilling contracts, I think the world’s largest ever completions contract, obviously a realignment in Brazil, all the biggest deepwater markets with some of the world’s best, most stable, consistent operators.

I’m not predicting what the world looks like six months, a year, three years from now, but these are five seven, eight year long contracts with price escalations and so forth. So no matter what, these are the rigs you want to be on and these are the customers you’re going to want to be working for.

So, I think our teams have done an excellent job in building a portfolio of some nice international work..

And in Latin America, nice pickup in margins there.

You made comments about margins at your Analyst Day back over this year, is -- can we move Maria’s goals forward at this point? And if so, where is Maria going next, could she [indiscernible] in Latin America?.

She -- the business is exactly kind of going the direction that we’ve mapped out. Our strategy has been risk mitigation followed by growth. As you can see by the realignment of the business in Venezuela and the repositioning in Brazil and some of the contract wins in Mexico, the strategy is following exactly -- the outcome is exactly as we planned.

So I’d say that risk mitigation is never anywhere off the table, but now it’s all hands on deck for topline growth and what I expect to see some nice incremental margins as these contracts emerge in Brazil and in Mexico, and then just a more appropriate business model for us in Venezuela should also be accretive going forward..

Okay. Great. And Martin, thank you, and Peter, best of luck in your next transition, and if it truly is a retirement, let’s go out and play some golf some time soon..

Thanks..

Thanks, James..

Thank you. And our next question comes from Kurt Hallead from RBC Capital. Please go ahead..

Interesting times indeed. I’d like to get your perspective -- you mentioned the work that you have done to increase your utilization on frac in U.S., you’ve got some new commercial terms and contracts from what it seems. I don’t want to harp on too much of the risk dynamics, but with oil doing what it is, I’d be remiss if I don’t.

So in terms of the contracts themselves, what’s -- is there any breakage fees or is it a situation where the terms are maybe more aligned with the Land contract drilling dynamic where they’re going to have to use the rig or they’re going to have to pay you some money if they don’t use your frac operations.

Can you just give us some color on maybe how these things are being structured and whether or not there is more, say, durability to the contract than maybe prior periods?.

There are, Kurt, granted, given our past and all, maybe I could safely say that the number of take-or-pay contracts in our portfolio is probably higher than ever for that particular product line in US Land.

Our customers, even as of yesterday, the key buyers are still biased towards securing capacity to deliver on their plans before year-end and into Q1. So, as I said earlier, there is no indication that these folks are going to abate or slowdown, just none whatsoever.

And then, on the cost side, if this does answer your question a little bit, 90% of our input costs around sand and freight are now under some kind of contractual arrangement. So our exposure to the spot cost side is not that -- I mean it’s a world of differences to what it was, say, this time last year.

So I feel secure with what our cost structure is going to be and we’ve improved the ability to more immediately pass things through. In terms of visibility, the systems are catching it. We have auditing, if you will, mechanisms in place to make sure that these things get passed on in a timely fashion.

So I’m very confident that in spite of the uncertainty that’s out there, the Baker Hughes pressure pumping business will navigate whatever, if you will, storms that should come to pass, if any, do..

They have to see $75 oil on the strip by December? Is it -- any framework that you can help us get our hands around, so we can get the same kind of conviction that you may on how you're going to work through this challenging environment?.

It depends on the customer, but if we leave off -- if we just look at the core most successful customers, I would say that it’s -- I think $75 is the starting point to where activity could start to slow.

I don’t believe anything above that and the second very big variable to that is the duration of it so we would see $75 next week, I don’t think you’re going to see one iota of activity slippage, none. But if we’re sitting at $75 come the holiday season or early into Q1, then certainly I think the conversations with the customers will be different.

So it’s mid-70s and it’s – we’ve got to see a few months of that to give it, as I said earlier, credibility that this isn’t just bouncing all over the place, because our customers are still in a pretty good economic – the right customers are in a pretty good economic position, the returns are still quite attractive and you know that.

So I don’t – and there is a bit of a competitive uneasiness that they are going to be able to get all their work done that they promised you guys they would do, and I don’t think they want to -- they don’t want to miss that.

So, right now it’s full steam ahead and I’m not and like you said most of the peers I talk to are not, my customer peers, aren’t nervous, they are concerned, they are not nervous, they are watching it closely, but if it should stay down below $80 for a while, then probably conversations will change..

Got it. Thanks for that. And Peter congrats and good to see a fellow Spartan do well..

Go green. .

Indeed..

Thanks, Kurt..

Thank you. And our next question comes from Marshall Adkins from Raymond James. Please go ahead..

Let’s shift to Russia.

How much have things been shut down there so far and what’s your sense of where we go from here let’s say over the next 12 months due to sanctions et cetera?.

First of all, I can tell you what’s happened. Our number one priority has been to make sure that we navigate this with full compliance and focus on both the EU and the U.S. sanctions. I’m confident in our systems, our software tracking systems that can really check everything to make sure that nothing is out of alignment to where it’s supposed to be.

I think the other thing that’s a bit missed or misunderstood I should say, Marshall, is that the number of rigs that are actually associated with projects that are being identified in the sanctions is pretty small, very few, very few, and the financial impact in terms of product sales or the services is absolutely inconsequential, and I think that’s going to even be going forward for the next couple of quarters assuming that the sanctions stay where they are because these projects are not that material.

The problem has greatly been the impact on the currency and I can’t predict where that’s going to go, and secondly, concerns about access to capital and just an overall, if you will, cloud that’s hanging over our customer community is slowing things down, adding friction to just the entire commercial relationship.

So what I think you’re going to see is just a shrinkage of what’s being spent there, not necessarily because of the sanctions -- not because it falls within the bounds of the sanction, but because there is just a storm cloud and people are not feeling optimistic about the outlook for their business in country.

Does that make sense?.

That’s actually – that’s very helpful. So it sounds like no massive impact yet, but maybe a slight downward trajectory due to the friction and obviously the currency, which was my follow-up, rubles has been hit but that’s not the only currency that’s been --..

That’s right. Exactly right..

So, on the currency impact that you had this last quarter, how much was ruble versus all the other currencies out there?.

It was predominantly the ruble, Marshall, it’s a little bit in the sands, the currencies are linked to the ruble, but it was predominantly the ruble. Not much else..

All right. Guys, thank you all very much. And Peter thanks for all the help over the years..

My pleasure. Thanks..

Thanks, Marshall..

Thank you. And our next question comes from Ole Slorer from Morgan Stanley. Please go ahead..

Thank you. Martin, I wonder whether you could just help with a little bit of a roadmap from the margin you delivered in North America in the third quarter to the fourth quarter, given the dual impact of the recovery in deepwater and the new pressure pumping prices and increased efficiency driving higher margins on land.

So, how should we think about the combined impact of the two? Which is the most important?.

Yes, they are absolutely the most important and then there is some peripheral supporting elements to write in terms of the technology, but as we highlighted, you can get to 13.5 just because of the missed activity by our customers than us in Q3.

As I highlighted I think in the first question, Ole, I don’t expect now -- the rig issue has not completely abated.

As we sit here today the currents are still an issue on the risers and on the associated rigs, so I think maybe one rig is going back out of the eight or so that were affected, but it’s not going to be a normal Q4 if and when these – not if, but when these rigs go back.

So we’re expecting an extremely strong Q4 that we didn’t expect when we were putting out our 15% guidance for North America. So Gulf of Mexico, while getting a slow start this quarter, could absolutely deliver more than what it normally would.

And on the pressure pumping and let me say this is while our model suggests that even if we don’t get a lot of the Gulf to come back, what we’re experiencing in this stimulation business right now could -- will definitely get us within spitting distance of it, and that’s a hard number to predict of course in terms of the costs and the timing of things on the pressure pumping, but it’s very, very robust.

So Canada continuing, we’ve got a little bit of a holiday impact, but I can tell you that some of the customer conversations are that they want to get these wells put online before the end of the year so there will be a holiday impact but may not be as protracted as it’s been in the past.

There was another element – there were some other challenges in West Texas you probably heard about we didn’t highlight it on the prepared remarks in Q3 was quite impactful on a couple of fleets in the Permian. That’s past us now.

So, I can’t give you an exact dollar for dollar, I just won’t do that, Ole, but there is not a lot that I could see that would hold its back other than a protracted holiday period these rigs for some unbelievable reasons just don’t get back to work in the GOM..

I was just -- thanks for that -- I was simply trying to back into how far along you are on the restructuring of the [indiscernible] pressure pumping division, both in terms of what you've done on the equipment side and the customer side and personnel side.

How far along are you?.

We are probably north of 80%, 85%. I mean I would tell you we’re 90-some-percent except that this is not an area you should ever be satisfied with. It’s infinitely perfectible.

The infrastructure associated with the logistics in moving the sand is just you wouldn’t recognize the organization relative whether it’s in the areas of purchasing or contract management or logistics, it’s completely overhauled. And there’s been quite a bit of talk about the impacts of North American logistics on the pressure pumping business.

I’m not telling you we weren’t up against the wall, it was tough, but we lost no work, disappointed no customers. The teams had all the product in the right locations with the right customers and those fleets got the jobs done.

We added another fleet and we’re optimistic of what the opportunities are to do some more of that in Q4 and we’ll update you on the Q4 call. I don’t want to tell you what our plans are. I‘d tell you what we’ve done in terms of adding capacity. The customer mix is overhauled probably entirely. There I can tell you it’s 100%.

Now it’s just managing the pricing and the past dues accordingly. So infrastructure wise, supply chain wise, customer wise, it’s all falling into place and again I could tell you that it’s all done but it’s not because it can always be better..

So, based on what you say, would it be fair to say that at some point in the fourth quarter, your pressure pumping group, as a whole, will start to close in on that mid-teens margin?.

The pressure pumping business in Q4 will still, it’s my expectation, still be dilutive to the overall margin number. Now, I’m only talking land, I’m not talking about the --..

Exactly. Yes, land, land, land..

Land only. Now in Q4, it’s still going to be dilutive to the 15%. That’s what I would project at this stage..

Lorraine, let’s go ahead and take one more question please..

Thank you. And our last question will come from Rob MacKenzie from Iberia Capital. Please go ahead..

Thanks for squeezing me in. Martin, I wanted to ask you a very difficult question you've gotten several times right now, but from a little different angle.

And that's, with the uncertainties at your customers in terms of commodity prices and what they are going to spend, how do you think about, in your budgeting process, what you're going to spend next year, particularly in the context of long lead-time items?.

That’s a great question and right down the heart of what we’re spending our time on. Let’s start with the most obvious which is pressure pumping capacity where we’ve done a great job in lining up the right type of suppliers to the equipment.

We’re great assembler, we’re a great designer, engineering of what the frac fleets of the future should look like, the objectives they are putting more horsepower on smaller footprints and the partnerships with that supply chain somewhat proprietary and we’re having conversations today in terms of -- with them in terms of what do we need starting in Q1 and Q2.

We’re going to need, I mean I think I mentioned to Angie, there is nothing that’s in the parking lot any more, and then within the context of the customer vis-a-vis their budgets, we are still looking at -- if we project -- if we even project a flat rig count, which we’re not at this stage, the well intensity is going to require a certain percentage, I’m not going to share with you what our estimates because we feel that’s kind of competitive, of additional horsepower to get these jobs done.

And our models also project or indicate and you’ve seen this in some of the announcements from our customers that can’t get the wells drilled with the budgets they currently got because they are spending more per well and we don’t see that trend changing.

The well results are fully supportive of longer laterals and more stages and more pumps per stage. So it’s just – it just doesn’t – it’s incongruous to suggest at this stage that we are not going to need more capacity on that front.

In terms of rental tools, if you look at the Middle East, if you certainly look at what’s going on in Brazil for us, if you look at what’s going on in Norway with Statoil and us, it’s biased upwards in terms of topline and therefore the capital to support it.

I don’t want to give you a projection at this stage but again we are not hearing anything from our customers, and Rob, a deepwater rig running today is going to be running next quarter and the quarter after that. They don’t slow down just because of a little bit of trickery around these commodity prices.

So, we’re pretty steady as she goes at this stage and that’s because that’s what we’re hearing from our customers and maybe that’s fortunate for us because of the way we’re positioned with these customers now. So we’ll just – we’ll leave it at that but it’s all going in the right direction..

Thanks, Rob. Lorraine, let’s go ahead and close out the call..

Thank you. Thank you for participating in today’s Baker Hughes Incorporated conference call. This call will be available for replay beginning at 12 PM Eastern, 11 AM Central and will be available through 11:30 PM Eastern Time on October 30, 2014.

The number for replay is 888-843-7419 in the United States or 630-652-3042 for international calls, and the access code is 3787-3932. You may now disconnect. Thank you..