The world’s largest oilfield services company said its earnings were hit in the first quarter because of a slowdown in shale drilling activity.
“First-quarter revenue of $7.9 billion declined 4% sequentially, reflecting the expected reduction in North America land activity and seasonally lower international activity in the Northern Hemisphere,” Schlumberger CEO Paal Kibsgaard said in a statement. Pricing for its services was “soft,” while fracking and other “drilling-related businesses” saw a dip in activity.
The company was unbowed, noting that the weakness in North America is offset by improving conditions globally. “From a macro perspective, we expect the oil market sentiments to steadily improve over the course of 2019,” as the OPEC+ cuts tighten up the market. Also, Kibsgaard said that the “weakening of the international production base” after “four years of underinvestment” will become “increasingly evident,” which should spark an uptick in spending.
The global E&P sector is “starting to normalize.” In fact, spending could rise by 7 to 8 percent this year around the world.
However, U.S. shale is in a different situation. After spending heavily for years, which successfully ramped up production to record heights, many shale companies are still not performing well financially. As a result, the U.S. shale industry is at somewhat of an inflection point. Kibsgaard said that the sector is “set for lower investments with a likely downward adjustment to the current production growth outlook.”
While the industry is looking up globally, the outlook for U.S. shale is rather downbeat. “[T]he higher cost of capital, lower borrowing capacity, and investors looking for increased returns suggest that future E&P investment levels will likely be dictated by free cash flow,” Kibsgaard said. “We therefore see E&P investments in North America land down 10% in 2019.”
There are additional problems unique to shale drilling that Schlumberger’s chief executive believes will continue to haunt the industry. “In addition, rising technical challenges—from parent-child well interference, step-outs from core acreage, and limited growth in lateral length and proppant per stage—all point to more moderate growth in US shale oil production in the coming years,” Kibsgaard warned.
It’s not all bad news for Schlumberger and its clients. As Bloomberg notes, the number of fracking crews deployed in shale basins hit a record high in April, up 12 percent since January. Production is still rising, albeit at a slower pace than in the past. The EIA forecasts a jump in output of 80,000-bpd in May, down from some of the more impressive monthly increases last year, but a very significant increase nonetheless.
Some analysts weren’t impressed. “The EIA’s DPR contained some significant downward revisions to shale oil supply. Last month the EIA estimated that supply from the seven main shale regions had
increased by 282 thousand barrels per day (kb/d) from December to March,” Standard Chartered wrote in a report on April 16. “This month it has revised the December to March increase down to just 42kb/d. Total oil shale liquids supply was also revised down 213kb/d to 8.38mb/d in April, including downward revisions of 83kb/d for the Permian, 84kb/d for the Bakken and 20kb/d for Eagle Ford.”
Still, a handful of new pipelines in Texas are expected to come online later this year and next, which could spark another round of drilling.
Overall, though, even as U.S. shale basins continue to attract prodigious levels of investment, the blistering rate of growth seen in the past few years may be at an end. Halliburton, another oilfield services giant, has yet to report its earnings, but it said in March that it expects North American oil producers to spend 10 percent less this year. Yet another challenge for Texas drillers is starting to crop up. The enormous volumes of light sweet oil in Texas is surpassing the region’s ability to handle it. The lack of pipeline capacity forced steep discounts in recent years, but now producers are having to discount their oil because refiners can’t handle such abundant supplies of light oil. Reuters reports that much of the oil coming out of the Permian has an API gravity in the 50s, lighter than the 40 to 44 degrees for WTI.
Because much of the Gulf Coast refining capacity is equipped to handle medium and heavy oil – blends that have become scarcer due to outages and declines in Mexico, Venezuela, Iran and constraints in Canada – they are having trouble processing so much light oil. Reuters says that some ultralight oil coming out of the Permian is facing discounts of $1 to $2 per barrel below heavier grades.
Discounts of a few dollars due to a quality mismatch with refining capacity won’t be the death knell for shale drillers by any means, but it adds to the growing list of challenges for an industry already facing significant questions about its financial viability.