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Key Takeaways from Schlumberger’s First-Quarter Earnings Call

By Elliott H. Gue on Apr. 29, 2015

When you consider the collapse in energy prices that has occurred since last summer, oil-field service giant Schlumberger (NYSE: SLB) reported solid first-quarter results, fueled by company-specific advantages, cost reductions and efficiency initiatives..

Management’s commentary on the broader outlook for the energy industry supports our thesis that oil and gas prices will stay lower for longer. Short-term rallies in oil and energy stocks aside, there’s more pain to come for the industry.

Although Schlumberger’s revenue tumbled 19 percent sequentially, the firm’s operating margins compressed by only 2.55 percent—impressive resilience in a challenging market.

In coming quarters, the market will pay close attention to Schlumberger’s decremental margins, or the extent to which declining revenue affects the company’s profits.

When Schlumberger’s revenue shrank by $4.461 billion between 2008 and 2009, the firm’s earnings before interest, taxation, depreciation and amortization (EBITDA) dropped by $2.609 billion—a decremental of about 59 percent ($2.609 billion divided by $4.461 billion). That is, during the last major collapse in energy prices, a $1 decline in Schlumberger’s revenue resulted in a $0.59 decline in EBITDA.

But in the first quarter, Schlumberger’s decremental margins came in at 33 percent overall and about 25 percent in the international segment, a significant improvement relative to the last major down-cycle.

The company also has the potential to win  market share from Halliburton (NYSE: HAL) and smaller competitors.

In particular, Schlumberger continues to push for ways to work more closely with its customers—exploration and production firms of all sizes—to implement its proprietary new technologies and reduce costs.

For example, during Schlumberger’s first-quarter earnings call, management highlighted several innovations that have gained traction with producers because they improve production while reducing costs. These advantages mean that the company can charge above-market prices for these products and services; these new technologies also help the firm to win market share from competitors.

In the US onshore market, two innovations stand out:

  • HiWAY: An approach to hydraulic fracturing that boosts and cuts the volume of fresh water and silica sand consumed during this critical process. Wells drilled using this technology in the Eagle Ford Shale showed a 26 percent improvement in hydrocarbon production over the first three months of their lives. Meanwhile, Schlumberger estimates that the 1,000 wells that have been completed with HiWAY saved 1.4 billion gallons of fracturing fluid and 2.8 billion pounds of proppant, the crush resistant granules (often silica sand) that prop open the fractured source rock and allow the oil and gas to flow.
  • BroadBand Sequence Fracturing: Introduced commercially in the early part of 2014, this stimulation technology isolates reservoir zones along the wellbore to make sure that they’ve been fully fractured. Management has reported strong uptake for this product and highlighted its usefulness in re-fracturing older wells, a strategy that some cash-strapped producers have pursued to boost production while lowering their costs.

During Schlumberger’s earnings call, management highlighted the paradigm shift underway in how oil-field services firms are compensated for their work. These risk-based contract structures reward the service provider for execution and, in some instances, could give them a cut of production.

The latter model holds a great deal of appeal in an environment where many customers have felt the crunch from lower energy prices and are desperate to lower their cost structures.

Simon Ayat, Schlumberger’s CFO, discussed the firm’s willingness to take the lead on project design and implementation and accept a cut of production as part of its compensation:

We’re not saying that we can do the work our customers are doing better. But I think given the capabilities that we have, I think we are underutilized today, and we have a lot more to contribute even into the design elements of the work that is related to our expertise. And I think by being invited to contribute, complementing the work that they are doing, I think we can achieve improvements in design and engineer costs out of the system before we go to implementation. And by factoring in our implementation, our execution capabilities in the design, I think we can also simplify and streamline the execution part of the work as well.

So, this is something that we are going to offer, Jim. Some of our customers might take us up on it and some of the others might now. And for the ones that are not, we will continue to work the way we’re currently doing. But I think this is something we are prepared to take on and put more skin in the game.

 

Of course, changing the contract model for oil-field services won’t happen overnight.

Schlumberger’s proposal likely will encounter resistance from the engineers employed by the major oil companies who would regard greater outside involvement as a challenge to their expertise and jobs.

However, these production-sharing agreements could gain traction in the US onshore market. A few years ago, Schlumberger inked a similar joint venture with ailing Forest Oil Corp to showcase the effectiveness of its HiWAY fracturing technologies. This approach to contracting didn’t catch on at the time, but shrinking cash flow in the US upstream segment could bolster the appeal.

During the company’s first-quarter earnings call, CEO Paal Kibsgaard highlighted the industry’s growing interest in re-fracturing mature wells that have been in production for several years.

By stimulating areas of the wellbore that weren’t fractured on the first pass, operators can generate solid production growth while lowering their cost structure. Focusing on existing wells eliminates the need for additional drilling or building gathering infrastructure to connect these sites to the pipeline and processing network.

Kibsgaard indicated that Schlumberger might be willing to foot the entire bill for re-fracturing work in exchange for a cut of production—if the customer allows the oil-field services firm’s engineers to select the wells.

If the transition toward risk-based contracts and production-sharing agreements continues, this model would favor Schlumberger and other diversified oil-field services firms, while smaller outfits that focus on a particular niche would themselves on the outside looking in.

This model would also reduce the up-front cost of producing hydrocarbons from US shale oil and gas plays. As producers and services companies continue to lower costs via technological, procedural and contractual changes, expect the break-even costs in key plays such as the Bakken Shale and Eagle Ford Shale to continue to decline.

Such an evolution would support our projection that US crude-oil prices will remain lower for longer. We expect the price of West Texas Intermediate crude oil ultimately to settle in a range that promotes some shale oil and gas development without incentivizing unrestrained production from plays with marginal economics.

This settling process won’t happen overnight and likely will entail a fair amount of volatility. Given the upstream industry’s huge cuts in capital expenditures and drilling activity, oil prices could head higher temporarily—only to be reversed by a flood of production and frenzied hedging to lock in higher prices on future production.

And with US producers able to sink high-probability wells within a week, this shadow capacity should keep a lid on oil prices once the commodity settles into its trading range.

Kibsgaard also asserted that cost reductions and efficiency gains eventually would help to make some second- and third-tier acreage economic to develop, though the focus will remain on the first tier for now:

I think if you look at what’s taken place over the past three, four years in shale liquids in North America, there has been a significant growth in activity and there’s been growing free cash flow deficit for the E&P industry. So that’s clearly not a sustainable way of the whole industry to operate there. Now with that said, I think there is a core part of the North America shale liquids that is viable even at current oil prices, and this will continue to be developed.  Now, as we go forward, as the industry continues to improve, I would say both on the cost side, although a lot has already been done, but even more so on the production per well, I think there can be a growing part of the, I would say, Tier 2 and Tier 3 acreage that can be developed.

But as of now I think we are limited more to the Tier 1 acreage at these type of world prices. And that’s why we’re saying that given the cash flow constraints we don’t expect that rig counts are going to come back to the previous levels around 2,000. It’s going to come back somewhere in between the current levels and where it was. And for the service industry, that means that the pricing concessions that are currently being given, we unfortunately are going to have to live with for a while because there’s going to be a pretty significant overcapacity for all sorts of services given the lower activity level that we’re going to recovery to. 

 

Extracting oil and gas is a capital-intensive endeavor. An extended period of elevated oil prices helped to fuel the shale revolution, but ready access to low-cost capital also played a critical role.

The majority of shale producers operated at a deficit in recent years, investing more in their operations than they generated in cash flow. These shortfalls forced them to borrow, in some cases heavily, to fund the difference.

(Click graph to enlarge.)US Upstream Cash Flow Shortage

So far in 2015, US exploration and production companies have issued or filed to sell $10.431 billion worth of common shares and $18.975 billion in bonds to help offset this widening gap. But this model won’t be able to sustain itself over the long haul.

The sharp decline in the prices of crude oil, natural gas and natural gas liquids over the past nine months have forced producers to reduce their drilling activity sharply to better align capital expenditures with cash flow. Accordingly, the US onshore rig count has plummeted by about 45 percent since June 30, 2014.

(Click graph to enlarge.)BHI Rig Count

Even with a barrel of West Texas Intermediate trading in the $50 to $60 range, many producers can still eke out a decent return in their core acreage; eventually, the US rig count will stabilize and begin to climb, as well-capitalized producers win market share by accelerating their development activity in their best plays.

And as costs come down, economics will improve to the point that producers will put additional rigs to work.

Bottom Line: Any decline in US oil production related to the falling rig count will prove temporary.

Kibsgaard also warned that although the rig count will recover, activity levels likely won’t return to the highs hit in 2014, when leverage and elevated oil prices fueled an orgy of drilling:

We further believe that a recovery in US land drilling activity will be pushed out in time as the inventory of uncompleted wells builds and as the re-fracturing market expands. We also anticipate that the recovery in North America land activity will fall well short of reaching previous levels and extend the period of weak pricing. 

That’s bad news for any oil-field service and equipment firm that derives a significant percentage of its profit from the North American onshore market.

In his prepared comments at the beginning of Schlumberger’s first-quarter earnings call, CEO Paal Kibsgaard indicated that the pace and magnitude of activity reduction in North America are almost unprecedented.

You have to go back to the mid-1980s to find a comparable period. That’s when Saudi Arabia and the rest of OPEC shifted their strategy from propping up oil prices by cutting output to ramping up production to win back market share.

(Click graph to enlarge.)Chart for SLB Piece

If the comparison holds, the recent rally in crude oil represents a short-term bounce to the top of a multiyear trading range.

Companies that provide crush-resistant silica sand look particularly vulnerable in the current environment; high prices for their product reflected accelerating drilling and completion activity and logistical constraints.

Even before oil prices plummeted and activity fell off a cliff, we expressed concerns that this market could swing to an oversupply—the main reason we sold Hi-Crush Partners LP (NYSE: HCLP) from our Model Portfolio for a 59 percent gain in April 2014.

We reiterated our negative outlook for Hi-Crush Partners, Emerge Energy Services LP (NYSE: EMES) and US Silica (NYSE: SLCA) in November, warning that these stocks could decline by 50 percent or more. (See Sand in the Gears: Elevated Downside Risk for High-Flying Proppant Producers.)

Although we took some flak for this out-of-consensus call, Hi-Crush Partners’ stock has given up almost 25 percent of its value and Emerge Energy Services, which announced guidance that implies a 56 percent distribution cut, has plummeted by 46 percent since then.

As for Schlumberger, the oil-field services giant remains the best-in-class name in its industry and should continue to deliver superior profit margins during this challenging period.

Nevertheless, the stock hasn’t pulled back enough to price in the severe deterioration in the oil-field services space; the shares have given up less than 25 percent of their value since its peak in 2014.

The only way to support the stock’s current valuation is to assume that oil prices will rebound to more than $70 per barrel—an unlikely scenario.

Based on normal trough valuations in a cyclical oil downturn, investors should have an opportunity to buy Schlumberger’s stock for $60 to $70 per share at some point over the next 12 to 18 months.

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