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Surveying the Oil-Field Services Landscape

By Peter Staas on Dec. 1, 2017

 

Third-quarter results from oil-field service companies demonstrated that the industry remains what Jeffrey Miller, CEO of Halliburton (NYSE: HAL), described as “a tale of two cycles” during the firm’s first-quarter earnings call.

Halliburton, Schlumberger (NYSE: SLB) and Weatherford International’s (NYSE: WFT) aggregate North American revenue surged 15.7 percent sequentially in the third quarter, while the trio’s international sales ticked up by 1.65 percent.

During Schlumberger’s third-quarter earnings call, CEO Paal Kibsgaard reiterated that activity levels in international markets had bottomed in the first quarter and cited the North Sea, Russia and the Middle East as areas of relative strength in the coming year.

Kibsgaard also highlighted the 14 or 15 final investment decisions made on upstream development projects as an encouraging sign and indicated that tendering activity in international markets had increased by 50 percent.

That said, this uptick comes off a low base and says nothing about the total value of these opportunities. Tenders can also take multiple years to translate into revenue overnight.

Meanwhile, excess capacity and cost deflation continue to present challenges in international markets, as oil-field service outfits compete to win a smaller book of business. Kibsgaard acknowledged these realities during the Q-and-A portion of Schlumberger’s third-quarter earnings call, but also indicated that “the downward trend of pricing is slowing significantly.”

Although incrementally more positive in his outlook than some of his peers (likely a product of Schlumberger’s revenue mix), Kibsgaard didn’t make any claims about a potential recovery in international markets.

Given the need for further cost deflation and visibility on oil prices for a meaningful pick-up in the multiyear development projects that predominate internationally, this market could bump along the bottom for some time.

Jefferey Miller, CEO of Halliburton, acknowledged these challenges and contrasted them to the North American market in his prepared comments for the company’s third-quarter earnings call:

Turning to the international markets, outside North America, our more conservative outlook for the last several quarters is proving accurate. Our customers around the world have different breakeven thresholds and production requirements, but all face the headwinds of the current commodity price environment. Due to lower cash flow and project economics, they are more focused than ever on lowering costs. The result of this combination is less activity and more pricing pressure.

In contrast to North America where we believe that a $50 oil price drives significant activity, customers tell me the longer duration international markets will react less to absolute oil price, but more to a positive view of where price will be for several years. This isn’t surprising given the longer investment cycle that many of our customers face.

Halliburton grew its international revenue by an industry-leading 4.2 percent sequentially in the third quarter, suggesting that the company is taking market share. However, Miller argues persuasively that the North American market offers the best near-term opportunities, given its shorter-cycle nature and the inflection in activity around $50 per barrel.

Pricing gains in Halliburton’s pressure-pumping business slowed in the third quarter, which management attributed to a slowdown in activity when oil prices slipped into the $40s per barrel. Meanwhile, CEO Jeffrey Miller echoed Paal Kibsgaard’s warning that fourth-quarter US land results would moderate because of seasonal weakness and customers exhausting their budgets.

However, Miller highlighted the oil-field service giant’s “encouraging discussions” with customers and reminded analysts that “$50 oil through the planning cycle is a good thing.”

The CEO also described two prevailing philosophies in the upstream segment: operators that are “very focused on returns” and “others that are going to shoot the moon because they like the acreage that they have.”

Miller’s comment acknowledges the much-ballyhooed shift in focus among some US exploration and production companies and speaks to the importance of service providers that can drive efficiencies for themselves and their customers. In this environment, economies of scale and innovations that enable customers to do more with less will win incremental business and push prices.

On Schlumberger’s third-quarter earnings call, CEO Paal Kibsgaard also highlighted the shifting priorities of US exploration and production companies, suggesting that growth in upstream capital-spending could moderate in 2018:

In North America land, where the E&P [exploration and production] companies have added significant CapEx [capital expenditures] over the past year, the production growth is so far falling short of expectations, driven by supply chain inflation, operational inefficiencies and the need to step out from the Tier-1 acreage. This has led to a moderating investment appetite, where the previous pursuit of production growth is now being balanced out with an equal focus on generated solid financial returns and operating within cash flow. This moderation can be seen in the flattening trend of the US land rig count during the third quarter and it is also reflected in our customers’ 2018 activity outlook.

Although Kibsgaard talked down the 2018 outlook for US onshore spending, capital expenditures in this segment were never going to match this year’s outsized growth—more than 60 percent relative to 2016. However, exploration and production companies’ robust hedging activity in the third quarter suggests that North American capital-spending could surprise to the upside relative to the caution seen in the back half of 2017.

Bottom Line: The tale of two cycles looks set to continue for another year. Drilling activity may have bottomed in the international markets, but pricing pressure will persist until price deflation improves break-evens and upstream operators have more confidence in the outlook for oil prices. Meanwhile, some US exploration and production companies may moderate their spending increases relative to last year, but this short-cycle market remains the best bet for incremental growth and pricing gains in 2018–especially if our call for oil prices to average between $55 and $65 per barrel pans out.

Given our preference for US exposure at this point in the cycle, we review the challenges, opportunities and market dynamics in three prominent onshore service lines through the lens of companies’ third-quarter results: contract drilling, pressure pumping and proppant.

Knowing the Drill

Although the number of oil-directed rigs actively drilling in the US land market has surged by 255 units since the start of 2017 (a 43 percent increase), the three largest onshore contract drillers’ shares have underperformed significantly this year.

Halliburton CEO Jeffrey Miller summarized the problem facing onshore contract drillers during the oil-field service giant’s third-quarter earnings call: “Today, the industry is drilling approximately the same footage as in 2014 with half the rigs, while completions intensity has significantly increased.”

Some of these efficiency gains have come from the rig providers themselves, including the advent of pad drilling, walking rigs, drill-bits that operate more effectively, predictive maintenance that reduces downtime, and increasing process automation.

Meanwhile, the development phase often requires fewer rigs and involves less downtime than sinking appraisal wells to capture operatorship and delineate a play; as this transition occurs in the red-hot Delaware Basin, the active rig count in the region may recede.

Well productivity has also improved by leaps and bounds, as exploration and production companies have increased per-well output by drilling longer laterals, tightening the spacing between stages, improving well placement, targeting productive horizons more effectively, and upping proppant loads—the crush-resistant silica sand that props open fractures in the reservoir rock, enabling hydrocarbons to flow into the well.

Earnings calls from oil-field service companies and exploration and production companies highlighted the innovations driving the next wave of productivity gains in the US shale patch.

Some of the hot topics that have emerged in recent quarters include strategies to improve near-wellbore stimulation and limit communication between infill wells to maximize output from larger-scale developments. To this end, spacing wells appropriately in stacked plays to limit interference will also be critical, favoring companies with robust proprietary data and a strong understanding of their acreage’s underlying geology. EOG Resources (NYSE: EOG) and Cimarex Energy (NYSE: XEC) are two operators that stand out in this regard.

Meanwhile, Halliburton and Schlumberger have emphasized their emerging big-data and machine-learning initiatives to unlock additional efficiency and well productivity.

Core Laboratories (NYSE: CLB) provided an update on its emerging gas-cycling solutions to extract incremental volumes from shale oil plays, improving the relatively low recovery rates of 8 to 10 percent. The company has more than 10 proprietary and consortium projects under way in the lab and will begin field testing some of these concepts in 2018. Management has noted that these techniques aren’t one-size-fits-all and require the right rocks and completion techniques for optimal returns. These projects remain in the early stages, but show promise and speak to the shale patch’s constant innovation in the quest for improved productivity.

How have contract drillers responded to these challenges? The three largest US players—Helmerich & Payne (NYSE: HP), Patterson-UTI Energy (NSDQ: PTEN) and Nabors Industries (NYSE: NBR)—aim to retain and take market share by upgrading their existing rigs with so-called super-spec capabilities needed to drill longer laterals efficiently and effectively.

However, the overhang of roughly 250 drilling rigs that contractors can upgrade to super-spec status relatively inexpensively—Helmerich & Payne estimates its costs at $2 to $8 million per unit, depending on the level of functionality—should keep a lid on leading-edge prices over the next few years. On the plus side, contract drillers appear to be exercising discipline and only upgrading rigs when the unit secures a customer commitment.

Equally important, the third-quarter dip in the rig count occurred when oil prices were rallying from their second-quarter swoon, underscoring how quickly operators can adjust activity levels. Without a sustained period where WTI exceeds $60 per barrel, pricing traction will prove hard to come by for rig owners.

And given the growing number of drilled wells awaiting completion, the industry may need to expand its pressure-pumping capacity before the rig count breaks meaningfully to new highs.

Contract drillers have sought to build market share and improve their profit margins through acquisitions that diversify their operations and/or make their rigs a delivery mechanism for additional services and technologies. We regard this trend as a tacit acknowledgment that the traditional rig-upgrade cycle and the push for pricing power will take longer to play out.

Patterson-UTI Energy has been the most active contract driller when it comes to deal-making this down-cycle, purchasing Canada-based Warrior Rig in September 2016 as part of an effort to develop the next generation of super-spec rigs. The manufacturer developed a top-drive engine with four motors that the driller had considered for its rigs.

And in mid-December 2016, Patterson-UTI Energy announced the purchase of bankrupt Seventy-Seven Energy in an all-stock deal worth $1.76 billion. The transaction netted Patterson-UTI Energy another 28 super-spec rigs and 500,000 horsepower of pressure-pumping capacity, as well as some lower-quality drilling units.

This transaction made Patterson-UTI Energy one of the largest hydraulic-fracturing companies in the US and gave this business line a footprint in the SCOOP and STACK plays, an area where completion activity is expected to be strong in coming years.

More recently, the oil-field services company completed the acquisition of privately held MS Energy Services, the No. 2 directional-drilling outfit in the US onshore market, ahead of Halliburton and Baker Hughes, a GE Company (NYSE: BHGE). MS Energy Services comes with a strong technology portfolio that includes one of the most reliable engines in the oil patch—the company uses these units in its own systems and rents them to third parties—and an antenna system for reliable, high-capacity data transmission.

A growing understanding of the important of well placement and quality to maximize returns from larger-scale developments has prompted a wave of investment in directional-drilling capabilities, a process that involves deviating the wellbore along a planned path as accurately as possible.

Schlumberger, which controls roughly 30 to 35 percent of the directional-drilling market, has sold out its PowerDrive rotary steerable systems consistently this year and expects strong growth for this business line in 2018.

Patterson-UTI Energy did well with the MS Energy Services acquisition and its diversification into pressure pumping, though the company has some catching up to do on the automation front.

Patterson-UTI Energy rates a buy on pullbacks below $18 for its solid balance sheet, proactive management team and leverage to upside in pressure pumping and directional drilling.

In May, Helmerich & Payne made its first acquisition in more than eight years, completing the acquisition of MOTIVE Drilling Technologies for $75 million and $25 million in potential earn-out payments. The software company, which was incubated and spun off by privately-held exploration and production company Hunt Energy, developed an algorithm-driven system to reduce drilling costs and deliver higher-quality wellbores without making concessions to speed.

Management the technology as “disruptive” and provided the following rationale for the acquisition during the contract driller’s third-quarter earnings call: “We expect an ongoing trend to more complex well trajectories with tighter well spacing and longer lateral lengths, resulting in the need to enhance control of wellbore placement and quality.”

Helmerich & Payne will allow MOTIVE Drilling Technologies to sell its wares to any rig contractor. The bull case for Helmerich & Payne centers on its industry-leading backlog of rigs that can be upgraded to high-specification units relatively inexpensively, potentially enabling the company to take market share.

However, we struggle to justify the stock’s more than 70 percent premium relative to its peers, especially when the management team appears content to sit on its laurels from the last major rig-building cycle and reluctant to pursue the integrated model favored by rivals.

This unwarranted premium likely stems from Helmerich & Payne’s position as the largest contract driller in the US and the stock’s 4.7 percent yield. Although management reiterated its support for the dividend on the company’s earnings call, the contract driller’s initial capital-spending plan for its fiscal 2018 suggest that it may need to borrow money to keep the dividend at the current level. Sell Helmerich & Payne.

Nabors Industries deserves credit for poaching high-quality talent from the likes of Schlumberger and National-Oilwell Varco (NYSE: NOV) to spearhead impressive innovations in rig technology that seek to automate, digitize and mechanize the drilling process to improve efficiency and reduce labor costs.

Strong uptake for the company’s SMARTRigs could bode well for future market share gains, though the contract driller will need to rely on building new rigs, as opposed to updating existing ones.

Despite this impediment, the Nabors Drilling Services division posted sequential revenue growth of 18 percent in the third quarter and profit margins of 26 percent. This segment houses Nabors Industries’ innovative technologies, including the recently introduced ROCKit Pilot system, which computes the wellbore path and automatically executes the drilling instructions.

We also like Nabors Industries’ partnership with Weatherford International (NYSE: WFT) to bulk up its ancillary service offerings, though both companies have checkered histories when it comes to execution.

The company’s pending acquisition of Tesco Corp (NSDQ: TESO), an oil-field service and equipment outfit that specializes in premium casing running tools, represents another step toward using the rig to provide integrated services for customers.

Although we like Nabors Industries’ strategy and investments in technology, the company’s net debt stands at 7 times operating cash flow. The all-stock acquisition of Tesco will provide a bit of relief on this front, but the company should consider cutting the dividend and selling noncore assets to give itself some more breathing room.

Given Nabors Industries’ balance sheet challenges, the stock tends to underperform in risk-off environments and outperform when sentiment strengthens–suggesting that the stock could catch a bid. Nabors Industries rates a Hold for now.

Getting Pumped Up

Whereas pricing power remains a dream deferred in the onshore US drilling market, a favorable supply-demand balance in the pressure-pumping service line has enabled operators to push through significant price increases in the first half of the year.

In part, this recovery comes because the US market for pressure pumping—the horsepower that propels the fracturing fluid and proppant into the reservoir rock to form cracks—faced a persistent oversupply even before oil prices began to weaken in summer 2014.

Accordingly, the market has had more time to heal on the supply side, with operators idling capacity and deferring maintenance. As of the first quarter, pressure-pumping capacity had declined 31 percent from the peak reached two years earlier.

On the other side of the equation, surging rig productivity has driven a significant increase in the number of drilled wells awaiting completion, as the existing fleet of pressure-pumping capacity struggles to keep pace. The inventory of uncompleted wells has grown rapidly in the Permian Basin.

(Click graph to enlarge.)
DUC Count

This lag between drilled wells and completed wells, coupled with recent strength in oil prices, suggests that oil and gas producers may allocate more capital to hydraulic fracturing in the first half of 2018 to work through this backlog–especially in the Permian Basin. After the rate of price increases in the US pressure-pumping market softened in the third quarter, stepped-up hedging by upstream operators suggests that activity levels could support further upside in 2018.

The big question for the pressure-pumping market is whether capacity additions—aside from capital, the business has a relatively low barrier of entry—will overwhelm demand, a real concern in a shorter-cycle market where customers can quickly scale activity up or down in response to commodity prices. Albeit a blip, exploration and production companies’ lack of urgency to complete wells during the third-quarter underscores this point.

To date, most of the capacity growth in this business has come from reactivating equipment idled during the down-cycle. Orders for new capacity represent about 5 percent of the market and have come primarily from smaller operators. In many instances, this new capacity merely replaces older frac spreads that have worn out.

Meanwhile, management teams from across the industry have asserted that prices haven’t yet recovered to levels where an industry-wide building cycle would make economic sense. We’d expect more activity on this front once the tight market—many pressure-pumping specialists report that their existing capacity is sold out—translates into more term contracts.

During Halliburton’s third-quarter earnings call, CEO Jeffrey Miller dismissed concerns about potential overbuilding, citing the wear and tear on equipment from additional fracturing stages and the larger volumes of sand and water involved in the current iteration of shale wells:

Now, first let me be clear. I believe that the [US pressure-pumping] market is undersupplied today. At the same time, equipment is being used harder and maintenance costs are higher. As a result, there will be a greater call for new equipment just to replace the active equipment that’s being worn out more quickly, meaning the day when supply and demand come into balance is further out than people think.

Next, completions intensity is not slowing down. We are pumping more sand with less equipment and as a result, the maintenance cost associated with today’s completion designs are increasing. The design of our equipment gives us an advantage over the market that even we have seen an increase in maintenance costs. I believe deferred maintenance is happening throughout the industry. A proxy for deferred maintenance and the simplest place to see it is in the industry horsepower creeping crew size. And while Halliburton continues to operate with an average fleet size of 36,000 horsepower per crew and have for the last several years, the rest of the industry is now averaging closer to 45,000 horsepower per crew. Deferred maintenance is creating this equipment redundancy on location.

Miller’s comments echo those of his counterpart at Superior Energy Services (NYSE: SPN), who continues to assert that the early phases of any new-build cycle would be geared more toward replacing existing capacity. CEO David Dunlap delved into this topic at length during Superior Energy Services’ second-quarter earnings call:

To supply and demand [in the pressure-pumping market], I mean, listen, from – all signs are that the market is extremely tight for capacity. I personally believe that some of the capacity that industry has activated in the first half of 2017 is capacity that did not have a whole lot of useful life of remaining to it. So, I think, even in a flattish demand market for hydraulic fracturing services that we continue to see tightness in the market, we’ve got fracturing fleets now that, with the types of hours that they operate are only good for four to five years. So, you think about the amount of equipment that we have working today and the amount that should be rebuilt or replaced during 2017, I don’t think we have that much capital rebuild and replacement going on today. So, that leads me to believe that we continue to see tightness in that market for quite some time.

Miller also pined that smaller pressure-pumping outfits would struggle to expand capacity beyond their current take-or-pay commitments, a claim that may apply to smaller, legacy operators but seems dubious when applied to the handful of names that completed initial public offerings earlier this year.

As for Halliburton itself, management emphasized that the oil-field services giant wouldn’t expand its capacity without commitments from customers, leading-edge pricing that boosts profit margins, and an acceptable return on investment. Other operators have also indicated that prevailing prices don’t support spending on capacity growth.

Bottom Line: Higher average oil prices in 2018 and robust hedging by US exploration and production companies–coupled with expected proppant savings as operators rely more heavily on local silica sand in the Permian Basin, Eagle Ford Shale and the Haynesville Shale–should provide a supportive environment for pressure-pumping pricing next year. Conditions also look favorable on the supply and demand side.

Going Big

Despite the profusion of pure-play pressure pumpers, we prefer Halliburton (NYSE: HAL) for its superior scale, a distinct advantage in a business line where the number of consumables (valves and proppant, for example) make well-oiled logistics a critical component of efficient operations.

Halliburton’s strength in other oil-field service and product categories can also help to limit the number of contractors (and therefore complications) at the wellsite and facilitate cross-selling. In an environment where oil and gas producers remain focused on unlocking efficiencies and improving well productivity, Halliburton’s scale advantages and superior uptime make it a reliable partner.

At the same time, oil-field service companies themselves aim to attract the highest-quality customers to maximize the utilization rate of their pressure-pumping capacity. Halliburton CEO Jeffrey Miller highlighted the importance of securing work from the strongest oil and gas producers:

Equipment utilization comes in a couple of forms. First, it has to be working and second, it has to be working for the right customers. Our fleet is sold out for the remainder of the year and into 2018. We continue to place our equipment with those customers who know how to effectively and efficiently use us to increase their productivity, which improves our utilization.

The disappointing profit margins posted by Superior Energy Services in the third quarter underscore the importance of working for the right customers and having a top-notch logistics game.

Management attributed this weakness to customer-specific delays stemming from unexpected well interference and logistics headaches. But perhaps the bigger challenge came from a smaller-than-expected proportion of so-called zipper fracs—the high-volume, single-site pressure-pumping jobs at the larger, multi-well developments pursued by Concho Resources (NYSE: CXO) and other high-quality operators.

Halliburton’s scale should also enable the company to push the envelope on automation and machine learning—innovations that promise to unlock further productivity gains.
Among the major US oil-field service companies, Halliburton boasts the best leverage to accelerating activity and pricing gains in the North America; in a momentum-driven market, Halliburton should benefit disproportionately from inflows to exchange-traded funds offering one-stop exposure to the industry.

Although Schlumberger remains a high-quality operator and is the industry leader in key service categories, its outsized exposure to international markets have helped to make Halliburton the go-to name for generalist portfolio managers seeking exposure to oil-field services.

Halliburton has also taken market share internationally in recent quarters, while investors have questioned Schlumberger’s recent pursuit of production management deals that involve taking an equity interest in upstream projects. With market and business momentum on its side, Halliburton joins our Focus List as a buy up to $50.

Although we see fewer near-term upside catalysts for Schlumberger, the company leads the industry in many product lines and has a solid track record of execution and innovation. Ongoing weakness in international markets will remain a challenge, but Schlumberger’s stock looks cheap for patient investors who have a longer time horizon. Schlumberger rates a buy up to $65, but we prefer names with more exposure to North America, as we expect short-cycle shale plays to take market share.

That said, we would stand aside on Baker Hughes, a GE Company (NYSE: BHGE), which already lagged its peers because of distractions related to Halliburton’s failed takeover offer and finds itself in more of a muddle with General Electric (NYSE: GE) likely to head for the exits as part of its restructuring plan. Baker Hughes rates a Hold.

Weatherford International (NYSE: WFT) may have jettisoned bungling CEO Bernard Duroc-Danner and embarked on a turnaround effort that involves cutting costs, monetizing noncore assets and focusing on core competencies; however, a stretched balance sheet continues to haunt the oil-field services company, even if it posted its first positive operating margins since the fourth quarter 2015.

Management’s guidance calls for cash flow neutrality in 2018, though much work remains to be done and the market (understandably) remains skeptical. Still, this stock can move up and down in a hurry, and the new management team hasn’t shied away from tackling the company’s challenges. Reports from Reuters suggest that the company could pursue joint ventures for some of its stronger business lines, an indication that everything is on the table to deleverage. We regard Weatherford International as a candidate for short-term trades, as opposed to a holding that builds value over time.

Sand in the Gears

The most robust price inflation in the oil-field service and equipment industry has occurred in the market for proppant, the crush-resistant silica sand used to prop open the cracks in the reservoir rock created during the hydraulic-fracturing process.

Some of these price increases reflect tightness in the market for higher-quality sands, a headwind that should moderate as the industry ramps up production at idle mines and brings new capacity onstream.

These tailwinds enabled Hi-Crush Partners LP (NYSE: HCLP) to resume paying a distribution in the second quarter, while US Silica (NYSE: SLCA) announced a share buyback plan after posting solid third-quarter results.

However, the impending boom in in-basin sand in the Permian Basin—where operators have announced plans to develop 80 million tons per annum of capacity—threatens to upend the industry and pressure margins. Given the timing of these projects, the first half of 2018 could be the peak for the proppant industry.

Although we expect proppant demand to increase again this year with longer laterals and stepped-up activity, Callon Petroleum (NYSE: CPE) and other operators have discussed the advantages of reducing sand loads to improve near-wellbore stimulation and limit communication between infill wells.

Halliburton CEO Jeffrey Miller once again highlighted the declining per-well proppant loads in the Bakken Shale and other mature basins, arguing that operators tend to overstimulate wells during the appraisal process when interference between fracturing jobs is less of a concern:

The facts are, for Halliburton, sand per well was down in the Bakken, Rockies and Northeast, and it was up in the Permian Basin. This happened because customers that know the production characteristics of the reservoirs have streamlined their operations to focus on cost per barrel of oil equivalent and are optimizing sand utilization. Conversely, those customers that are still drilling to hold acreage or exploring production boundaries of their reservoirs are continuing to pump jobs with higher sand loads.

Bottom Line: We prefer to stand aside on the major proppant names because of concerns that the top of the cycle may be closer than management teams admit. At the same time, the price relief from pumping more in-basin sand in the Permian Basin could give oil-field service companies an opportunity to push prices in other completions-related categories.

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