Working Over The Oilfield Service Sector

Hurray for the recovery, right? With the U.S. rig count more than doubling since the bottom in May 2016, the E&P sector eems to have dusted the residue of the long and painful downturn off its shoes and is plowing forward with new growth projections. All is well if your balance sheet is well, and even better if you’ve got Permian exposure.

But what about the services side of this equa-tion? Even with renewed activity in certain domestic plays, the anticipated price inflation that is expected to pull the sector out of the realm of sub-zero margins has barely materialized. And what is good for U.S. shale players ramping up land rigs is still merely a happy thought for off-shore or international exploration.

At left, this recent Halliburton Co. hydraulic fracturing operation in the Permian Basin illustrates the urgency the service sector is experiencing to ramp up in select North American plays. (Photos courtesy of Halliburton)

With so many questions lingering over the durability of the oilfield service sector, Oil and Gas Investor reached out to two of the world’s largest service companies—Halliburton Co. and Weatherford International Plc—to discuss the status of the industry today and how they are positioning themselves for the anticipated, albeit lagging, upswing. Both companies have recently transitioned with new leadership in the CEO position.

Eric Carre is executive vice president, global business lines, and chief health, safety and envi-ronment officer for Halliburton. The company is the second-largest global provider of oilfield services with 50,000 employees in 50 countries. Following a $34-billion attempted merger with Baker Hughes in 2015 that was ultimately scut-tled by the Department of Justice, Halliburton is happy with the breadth of its current portfolio, Carre said. “We’re not looking at changing.

“There have been a lot of questions and rumors about whether or not we would get in the subsea business,” Carre said, but, “it’s not something that we’re interested in. We think that there are good players available in the market for us to partner with if the industry goes in that direction. Our key focus right now in terms of M&A is technology acquisition and improving the scale of some of our product lines.”

Mario Ruscev is executive vice president, president of product lines and CTO for Weatherford, with some 30,000 employees in 90 countries. Similarly, Weatherford is focusing on industry partnerships to expand its reach rather than consolidation. One joint venture marries Weatherford’s well construction expertise with Nabors Indus-tries Ltd.’s fleet of measurement-while-drill-ing rigs. Another, on the well stimulation side, joins Schlumberger Ltd.’s technologies and fleet with Weatherford’s in a combined effort branded as OneStim.

“We believe the market will still be com-plicated and difficult for quite a while, which means we cannot continue to do everything we did before; we need to focus. Having a heavy presence in pressure pumping no longer made sense for us. For both sides, OneStim makes a very nice, coherent pack-age. It’s not very often you have a win-win partnership; in this one we have it,” said Ruscev.

Investor met separately with both executives and presented them with a similar slate of questions.

Investor Is the downturn over?

Carre I think you have to distinguish what’s happening in North America and what’s happening in the international part of the business. If you look at North America, we hit bottom sometime in Q2, Q3 of last year. We’ve been on the rebound since then.

It’s been a bit different in the international sector, where we’ve only hit bottom in terms of activity in Q1. The international sector still remains very challenging in terms of pricing. Ruscev It really is very simple: The oil price will go to a certain level, people will start pumping like crazy and the oil price will get depressed again. It will continue like that with ups and downs. I don’t really know what is the right level.

We lived through a bubble from 2002 to 2014. Those prices are not coming back, ever. What-ever people dream of, they’re not; they should not look in the past. I believe that the price of oil will be limited by the cost of extraction of unconventionals. What saves us is that unconventional production is still quite expensive. Investor The industry is notorious for over-producing during price spikes. How do you adjust to those swings?

Ruscev We can do that; we have been doing that forever. Remember, during this bubble, we all became fat and lazy. Before, we were lean and aggressive. We just have to readapt to where we were.

I don’t think the swings will be the size that we just went through. For me, this was the burst of a bubble, which is different from nor-mal swings that you have in the industry. In the ’90s, we could take swings of 20% to 30% very easily, but we were different then. I don’t think we’ll go back to that, but we’ll have to adapt to be at least as agile.

Investor How are the dynamics different between North America and international?Carre The North American market is much more of a transactional market. It is driven by companies that have a short-term horizon; you typically get your money back in a couple of years. The international sector takes a more long-term view and is a more contractually driven type of environment.

Investor What did you do to improve your business during the downturn?

Ruscev Well, first, like everyone else, we had to make cuts to our budget and workforce. It was unfortunate but it had to be done. Then we had to choose what we want to focus on. We are not the biggest; we cannot fight every battle. We have to choose where we want to be the best and where we want to grow.

We decided that we want to be best in two areas. One is well construction—from drilling to completion, because a well without the com-pletion is just a hole. We have a lot of history, and we’re very strong in that. The other one is production optimization. It’s more than just artificial lift; think of it as making old wells more producible. We have wonderful wire-line tools that can diagnose whatever needs to be done to a well or to a set of wells to be revamped and rejuvenated.

Investor Which of your business sectors are most active now?

Carre The businesses that are most driven by North American activity, and the businesses that touch the completion part of the business. At the peak of the cycle in 2014, we [the U.S. land industry] had 2,200 rigs drilling or just about. Then we hit the bottom of the cycle and we were below 400 rigs. Now, we are back up to about 900 rigs drilling in U.S. land, which is more than double what we were at the trough of the cycle, but is a far cry from what we had at the peak. That means that the well construction or drilling-related businesses that are primarily driven by well count are still running at much lower activity levels than we saw at the peak.

What’s different with the completion part of the business is that the intensity of completions is so much higher today than three, four, five years ago. On 900 rigs, we are actually seeing a much higher level of activity in a business like hydraulic fracturing, for example, than when we were running 2,000 rigs. That’s because we drill much longer laterals, we do a lot more stages per unit of reservoir length and we have stages that are more intense in terms of volume of proppant pumped.

Investor In the U.S, what percentage of your existing frack fleet is currently deployed, and how many new frack crews do you plan to bring back on this year?

Carre We’ve publicly announced that we are reactivating all of the frack spreads that we had stacked. We haven’t made a formal decision yet as it relates to building new spreads, but it’s something that we are considering, and if the conditions are right we’ll do it.

The bottom line is we need to generate a return on our investment. You need to be confident that your customers are going to stay active. For them to stay active, then they need to be comfortable that commodity prices are going to remain at a certain level.

Investor So then, stable prices?

Carre A stable price and a more stable outlook. There is still a lot of risk right now. Inventories are still high. Commodity prices haven’t necessarily firmed up to the level that people thought they would six months ago. Investor What’s happening with pricing today? Are you able to drive margins at $50 oil?

Ruscev We’ll have to adapt to drive a margin at $50, and we are doing that. We’re not there yet, but we are in the process, and we will get there. We have no choice. Supply and demand drive the price in the long term, and the pricing is the pricing.

Carre Pricing is improving, in particular, on the completion side of the business. We’re seeing fairly healthy price increases in hydraulic fracturing, much less on the other businesses, but it’s starting to happen as well. We have a long way to go before we get back to price levels that are sustainable for the service sector.

Coming out of the downturn, Weatherford determined to focus its efforts in two primary strengths—well construction and production optimization.

Investor What should operators anticipate?

Carre The whole service sector has been underwater for the last couple of years. We have not returned cost of capital. Like our customers, we have to return and deliver value to shareholders. For the most part, when we talk to our customers, they understand. They went through the same cycle. Not many of our customers were making money last year.

Ruscev From the operators’ perspective, first there was the shock, and they thought, “Okay, I’ll squeeze my subcontractor and solve it.” It’s probably only in the last nine to 12 months that they’ve started to realize that maybe they have to adapt, too. In the end, there is one thing that counts in our industry for an operator: what is the full-cycle lifting cost? This full-cycle lifting cost has to be below the price of oil. If it’s not, you have to change or die, because you can’t survive.

It’s very hard now, because many operators still have a lot of debt. To survive, they some-times need to pump just to pay the debt. When you hear people tell you, “I’m cash positive at $40 or $35,” that depends on what you count as cash positive. There was a huge amount of sunk costs into [accrued] debt or somewhere we drill much longer laterals, we do a lot more stages per unit of reservoir length and we have stages that are more intense in terms of volume of proppant pumped.

Investor In the U.S, what percentage of your existing frack fleet is currently deployed, and how many new frack crews do you plan to bring back on this year?

Carre We’ve publicly announced that we are reactivating all of the frack spreads that we had stacked. We haven’t made a formal deci-sion yet as it relates to building new spreads, but it’s something that we are considering, and if the conditions are right we’ll do it.

The bottom line is we need to generate a return on our investment. You need to be con-fident that your customers are going to stay active. For them to stay active, then they need to be comfortable that commodity prices are going to remain at a certain level.

Investor So then, stable prices?

Carre A stable price and a more stable outlook. There is still a lot of risk right now. Inventories are still high. Commodity prices haven’t necessarily firmed up to the level that people thought they would six months ago. Investor What’s happening with pricing today? Are you able to drive margins at $50 oil?

Ruscev We’ll have to adapt to drive a margin at $50, and we are doing that. We’re not there yet, but we are in the process, and we will get there. We have no choice. Supply and demand drive the price in the long term, and the pricing is the pricing.

Carre Pricing is improving, in particular, on the completion side of the business. We’re seeing fairly healthy price increases in hydraulic fracturing, much less on the other businesses, but it’s starting to happen as well. We have a long way to go before we get back to price levels that are sustainable for the service sector.

Investor What should operators anticipate?

Carre The whole service sector has been underwater for the last couple of years. We have not returned cost of capital. Like our customers, we have to return and deliver value to shareholders. For the most part, when we talk to our customers, they understand. They went through the same cycle. Not many of our customers were making money last year.

Ruscev From the operators’ perspective, first there was the shock, and they thought, “Okay, I’ll squeeze my subcontractor and solve it.” It’s probably only in the last nine to 12 months that they’ve started to realize that maybe they have to adapt, too. In the end, there is one thing that counts in our industry for an operator: what is the full-cycle lifting cost? This full-cycle lifting cost has to be below the price of oil. If it’s not, you have to change or die, because you can’t survive.

It’s very hard now, because many operators still have a lot of debt. To survive, they some-times need to pump just to pay the debt. When you hear people tell you, “I’m cash positive at $40 or $35,” that depends on what you count as cash positive. There was a huge amount of sunk costs into [accrued] debt or somewhere else. At the end you have to be able to take care of all of it. We really need to go back to full-cycle lifting costs. We are still functioning under fumes of the past bubble. We have to go back to being healthy.

Investor Did you slow down your R&D during the downturn?

Ruscev Oh yes, we slowed down everything; we had to survive. Everybody has cut down their R&D budget, we all know that. It would be lying to say we did not. But we were selective of where we slowed down. We made sure we kept going 100% on some technology, and we slowed down on some other technology.

The nice thing is we have a lot of projects in the pipe. I think the industry needs it.

Investor For instance?

Ruscev Think of offshore. The cost of operating offshore is expensive, and not just because building the well is expensive, but also the amount of money spent after that, even on very simple things. For example: Changing out an ESP [electrical submersible pump], depending on the price of the rig, is probably $30 million. It’s a lot of money.

We have to design things that will live a long time. That means metallurgies, sensors and equipment that will adapt to the changes of the reservoir. As you pump, the thermodynamics change.

Dreaming of the future, I see completions that are made of intelligent metal that measures the pH and shuts down by itself when the pH changes. You don’t have to do it manually. If we want to be able to produce these offshore assets 10, 15, 20 years from now, these are the kinds of things that need to happen.

Investor Eric, how did Halliburton’s R&D fare during the downturn?

Carre I think we behaved similarly to the rest of the industry. We try to affect our tech-nology spend as little as possible through downturns, but the downturn here was so significant that we had to reduce some of our technology investments. We did reduce the amount of dollars spent on technology, but as a percentage of revenue for the company, the spend was about the same as in the upcycle. Investor It does seem like there is more uptick in technology improvements during downturns.

Carre Beyond the actual dollars of the invest-ment, we went through a significant shift in terms of where these dollars went.

Prior to the downturn, if you go back to 2012, 2013, we had an industry that was very active in deepwater and exploration. A significant portion of our technology dollars were aimed at these market segments. Then the downturn hit, and the whole industry started shifting. We’re sitting now on a recovery that looks very different than [what the industry] looked like five years ago. We are looking at a deepwater business that is much smaller, and a significant ramp up in the unconventional land business.

It’s going to be a while before we see explo-ration or deepwater activity levels as we saw them five years ago. Deepwater is going to come back, that’s not the question, but it’s going to be a while before it comes back at levels that we experienced in the prior cycles. As a result of this, we shifted some of our technology dollars to unconventional and land-related technologies.

Investor There’s been a lot of talk about how much more efficient operators have gotten in the shale plays. Do you consider that an efficiency gain or a result of enhanced completions?

Carre You hear efficiency defined in different ways. From an operator perspective, per dollar of investment, they are getting a lot more production out than they did a couple of years ago. We tend to put that in three different buckets. Number one is the service cost. It is a lot lower than it was a couple of years ago. Unfortunately, we’ve been at the end of the stick on that one. The whole service sector has been operating underwater for a couple of years because of that pressure in pricing. That’s been one of the main contributors to the efficiency.

Second, activity has been reduced. As you go from 2,000 to 400 rigs, you obviously keep the best rigs, you keep the best crews and you drill of everything, which contributes to increased efficiency as well.

Third is true efficiency improvement. As an industry, we are operating in a much more efficient way than we were before. We drill and frack quicker, and the whole intensity of how that works is much better than years ago, with improvement in technology, improvement in processes, improvement in work methods.

In terms of the contribution of each bucket, some people think it’s about a third, a third, a third. My personal view is half is from the service sector cost.

Investor In terms of driving efficiency, could you point to an example that Weather-ford is doing?

Ruscev We’re drilling longer wells—recently we’ve broken a couple of records in the Eagle Ford. But now most of the cost is not on the drilling side; most of the cost comes during completion and production. So the next big win will be about better [reservoir] characterization, making sure that we really optimize the completion, we really understand the production, we use more data and we’re able to analyze more data.

Now people do a lot of analytics, which is very empirical. They take global data from all the wells and try to optimize. When people use analytics, they need 70 to 100 wells to be able to do it. Even with the average cost now down to $5 million per well, it’s still a half-billion-dollar investment before you can start being predictive. It’s expensive.

The next big challenge will be to better understand the flow based on better reservoir characterization in order to pinpoint exactly where to frack. This can be achieved through modeling. That’s probably the next revolution.

Investor What are the biggest technical challenges that the E&P side is facing today, and how are you addressing those?

Carre The efficiency improvement in terms of drilling and well construction has been tremendous, but the biggest gains that remain to be generated are in production and recovery. If you look at unconventional recovery rates, the consensus is they’re still in single digits. If we could get up to 15%, that would truly be a game changer. There are a whole slew of technologies that we’re working on in terms of better understanding how we design hydraulic fracturing jobs and how we place wells.

What we are becoming better at is learning from other industries and applying that to our own. There’s a lot of discussion now around digital, what we can do with automation, what we can do with analytics. This is going to make a difference in how the industry functions over the next five to 10 years.

For example, we’re launching a product that has the ability to run a cementing job completely remotely. Folks in a remote room can run the entire cementing job, activating valves and doing the mixing, the pumping, everything. That’s really slick technology.

Ruscev The consequence of the bubble we just came out of is that we stopped being creative because we were all well fed. I remember a few years before the downturn I would say to an operator, “We need to do something different to be more effective.” Usually they said, “You know, I have 200 wells to drill in the next two months.”

Now, we are in a situation where you really have to be effective in order to make money at $50 a barrel. In the next few years—because it will take time until people get back into the swing—we will see much more technology coming.

Investor What kinds of technology might that be?

Ruscev Drilling costs have come down and now represent 20% of the work, 25% max. Most of the rest is the completion. Here, the industry hasn’t really changed anything in a long time; we’ve just made everything bigger. We produced two times more because we injected two times more sand, but this is two times more expensive. Now that we have reduced drilling costs, which are a small fraction now, we need to focus on the big costs: the completion, fracturing and injection.

Published data show that half of what we frack is not really producing. Fracking when you’re not producing is never good. It’s not very complicated to take enough measurements to only frack the areas in which you believe you can produce more. That’s an easy way to make a difference.

Additionally, remember that shales are not totally homogeneous. Over a couple miles-long well, you’ll see things change a few times, and the relationships between the frac-tured zones and the natural fracks are very sensitive. We’ve realized that, in the same reservoir, by placing the well differently and optimizing the way it would flow, we could increase the total surface created by a factor of 10. You can assume that, everything else being equal, if a surface is effectively ten times bigger, you have a chance to produce ten times more.

Investor If you could point to the best technological improvement that your company is offering to your customers in 2017, what would it be?

Ruscev Just one? It’s like picking a favorite child, and I have so many favorite children.

We have 160,000 wells in the world which are monitored by our life-of-well information software called LOWIS, which is a great soft-ware product, but we took the opportunity to revive it for this new era. We’ve totally repackaged it, making it a modern software that is part of ForeSite, a total production optimization platform. We’ve linked it to our analytics tools. Bringing all of the data together will enable users to predict when [field] hardware is going to fail. That will allow customers to completely change the way they do maintenance service.

With the next level of the ForeSite platform, we will be able to locally optimize drainage at every pump, and then link all these pumps together to optimize the total drainage. This represents a big value, because if you can improve the drainage by a few percentage points, you have big profits.

ForeSite is part of a whole strategy that we have to regroup all of our software products, including our Cygnet SCADA system. We have another little project that we’ll introduce in 2017 related to the Internet of Things and Big Data. We have a setup where, on every sensor, we can put a little Bluetooth box. These all link to a central box that manages all this data, makes sure it is secure, and you can send that data anywhere you want. Once we introduce it, the cost of installing and maintaining production equipment will go from $100 million to $10 million, because there is such a huge difference in the infrastructure.

These are the kinds of things we’re doing which I believe will make a huge difference in efficiency for the customer.

Investor What’s your outlook for U.S. onshore for the remainder of this year?

Carre Very positive. We think activity is going to continue growing. I wouldn’t be surprised if we break the thousand rig mark by the end of the year. A lot of our customers have significant hedges in place. They’re less sensitive to commodity price variation. Right now, even though there’s risk in commodity prices, we don’t really see things crashing to the extent that it would affect activity in significant ways. We’re very optimistic for the near future in North America.

The area that has absorbed most of the capital is the Permian. That’s where we have seen most of the activity picking up. We have seen a significant increase in activity in the Northeast as well, where new pipelines are coming online.

Ruscev The demand is here now. I was giving a talk in Oklahoma two months ago, and people asked me, “How do you feel about the rig count at 800?” Frankly, I would feel better if there were 600 rigs, not 800, because with fewer rigs, I’d be more confident that we would not overproduce and kill the price. It’s a hard balance to achieve. This is the land of the free, and we’ll shoot ourselves in the foot by overproducing. It’s bound to happen.

But unlike the last swing, it will be little adaptations—the price will go up and down and up and down. I still believe as an industry we need to accept that this is a new world, and we need to adapt.

As the North American land business ramps up, Halliburton has reactivated all of its idled frack spreads but will build new spreads only if operators show resilience in activity commitments.

Investor What do you see happening internationally?

Carre We’re going to start seeing a slow pickup of activity with the main areas of recovery being the Middle East, Russia and the land business. I think we’re going to see offshore recovery after all of that. Our priority list in terms of recovering is, No. 1 by far, U.S. unconventional, then the Middle East and Russia, then other land markets in the international business then, following that, some recovery in the offshore business and in exploration.

Investor What is your prognosis for the deepwater market?

Carre I do not believe we’re going to see any significant recovery before a couple of years to the level that we saw before. The focused on the Gulf of Mexico and in Brazil. In West Africa, the cost structure is very challenging. It’s going to be a while before that goes back to a high level of activity.

Investor You don’t see deepwater economic at today’s prices?

Carre Some of it. The Gulf of Mexico can be economic, Brazil can be economic. It’s very difficult to see new development in some countries in West Africa working at $50 oil.

Ruscev It’s all about supply and demand, as well as pricing. Whatever can be produced at $50 a barrel will do well. Whatever cannot is in trouble. If one day demand is so big that the guys in the shale cannot compensate at $50 a barrel, then the price will go up.

I am pretty optimistic on demand. Think of one thing: The consumption of oil per GDP per habitant in India is 1 barrel per year. It’s 2.5 in China, 20-plus in the U.S. and 17 in the OECD countries. Even in countries like Turkey and Malaysia, it’s around 5 to 7. We have to assume that China and India will go to 5 or 7. That’s a lot of oil, even if you include all the alternatives to hydrocarbons.

Investor Will we see cost efficiencies in offshore deepwater markets similar to onshore to function in a lower-cost environment?

Ruscev I think so, yes. Because investment in offshore is so long, it will take time. The big difference that we have now from before is that we are sitting on a bunch of oil which can be put online within six months. There is a lot of it, and I think it changes everything.

Carre Yes. We’ve [already] seen cost reduction on some specific projects to the order of 40% to 50% through more standardization, better design and, of course, through the overall [lower] service sector cost as well. Overall, we’re seeing a lowering of the breakeven point for deepwater too.

But the time horizon is still much longer than what we’re seeing in unconventional and in the land business. That longer time horizon gives you a lot less flexibility in terms of how you manage capital from an operator perspective. That has a very significant influence. Plus, since you start producing five to seven years from now, the risk level and uncertainty around commodity prices are much higher than in unconventionals.

Investor Do you think the balance has shifted to where there’s going to be more onshore unconventional production vs. the offshore?

Ruscev In some offshore wells, you have such permeability you can produce 60,000 barrels a well [per day], but it’s just too expensive now to build that well. We have to adapt, but we are not there yet.

The last few years, all the drilling was deeper, bigger and more expensive. It cannot always be bigger and bigger. There has to be a dramatic change in philosophy. You have to think of the wells from a totally different point of view.

Investor What does that look like?

Ruscev Wells that have not as much infra-structure; truly intelligent wells.

Investor Will the service sector reach a short-term bottleneck of available resources? If so, how long will it take to realistically ramp up to meet a further call from the industry?

Carre There are bottlenecks across the board right now, specifically talking about North America. There are bottlenecks around people, which so far we’ve been successful in addressing. We have a high success rate in terms of our ability to recruit people. The first folks that we go to are the Halliburton [employees] that were unfortunately let go during the downturn.

There are bottlenecks in terms of equipment as well. A lot of companies use the same sup-ply chain, so that’s a bit of a challenge. From that perspective, we are at an advantage in the sense that we manufacture our own equip-ment. We rely less on supply channels than some of our competitors, but we have to buy some parts, so there is still some level of challenge there.

The third challenge relates to running day-to-day operations, buying and moving material. There’s been huge inflation on the sand side of the business. Then logistics—the quantities of sand that we have to move day in and day out—are just incredible. Using the scale and the logistics network that we’ve built over the last 10 years gives us an edge.

Ruscev I think we’ll figure it out. If you want more people, you might have to pay more, but you can get them. That’s one thing we are good at. We have enough engineers now. We did let go of a lot of field personnel. They are not coming back.

Investor What’s your outlook for the next 12 months, and what are you most excited about?

Ruscev I’m really looking forward to seeing the joint venture with Schlumberger kicking in, in North America. I think there is a huge potential and that it will be a lot of fun. In fact, all of our product lines in North America are growing—we are basically at capacity in drilling now, and all the well construction is doing really, really well. It’s exciting.

Then our position internationally is becoming quite solid. We are growing our position in the Middle East and North Africa.

Carre I’m most excited about the fact that 2016 is over! That was a very painful couple of years in the history of our company. To basically be able to go back and hire people again, train people, focus on growing the business again, to collaborate and engineer solutions to maximize asset value for customers, it gives a totally different sense of purpose to an organization. It’s a lot more invigorating. That is really what I’m looking forward to.