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Global Oil Demand Could Leave Gaping Hole: Fuel for Thought

Stocks Rocked the House Post Midterm Elections

Oil refining executives wary of RFS program despite falling compliance costs

Oilfield service majors to limp into 2019 as North America land market struggles

Strong shale output drives major US oil producers' earnings to multiyear highs


Global Oil Demand Could Leave Gaping Hole: Fuel for Thought

Global oil demand growth was a much heralded sidekick to supply cuts that rebalanced the market in record time. Now the Saudi Arabia-Russia pronged pact is considering reversing course on its output cut deal, while demand growth shows little sign of letting up.

That risks leaving a hole in the market that the OPEC alliance will struggle to plug.

Oil bulls listening to Jeff Currie, Goldman Sachs’ head of commodity research, at the S&P Global Platts Crude Oil Summit earlier this month would have been rubbing their hands with glee. He stated he was his most bullish in a decade.

“The underlying demand trend is what is dominant here, not the OPEC production cuts. That is secondary,” Currie said.

OPEC and 10 other countries embarked on a plan to remove 1.8 million b/d in late 2016 to wipe out a more than 300 million barrel stock overhang. And that mission has been accomplished well ahead of the deal’s expiry at the end of year, thanks to over-compliance to the cut quotas and a healthy appetite for crude.

It’s an appetite that has been called into question at higher prices. But a look at the forecasts from major institutions such as the IEA, IMF and S&P Global Platts Analytics shows that the consensus is that demand is set to remain robust.



Stocks Rocked the House Post Midterm Elections

After the S&P 500 logged its 9th worst Oct. on record, losing 6.9%, it has bounced back 2.6% month-to-date through Nov. 9, 2018. Though the monthly returns for the eight Novembers following the historically bad Octobers were only positive twice – in 1978 (President Jimmy Carter midterm year) and 1933 – the fact there was a midterm election this year may help the chance of a solid rally if history repeats itself. Historically, the S&P 500 has been positive in most periods after the midterm elections.

In the months of Nov. and Dec. during historical midterm election years, the S&P 500 gained 14 of 22 times in Nov. and in 15 of 22 times in Dec. with a combined 2-month gain in 17 of the 22 midterm election year-ends. In percentage terms, the S&P 500 gained in 64% of midterm election Nov. months and 68% of the following month that when combined into a 2-month return resulted in gains 77% of the time. Also, the magnitude of the average gains in the 2-month period was 6.1%, more than the magnitude of the average loss of 4.1%.



Oil refining executives wary of RFS program despite falling compliance costs

While the price of biofuel blending credits has fallen toward insignificance, the uncertainty surrounding the direction of U.S. biofuel policy has some U.S. refining executives looking to limit their company's exposure to an opaque market that they see as primarily driven by politics.

The Renewable Fuels Standard, or RFS, program, administered by the U.S. Environmental Protection Agency, requires U.S. refiners to blend an increasing volume of biofuels such as ethanol into the transportation fuels they produce each year, escalating to 36 billion gallons by 2022.

The EPA sets annual renewable volume obligations each year based on overall volume requirements and projections of domestic gasoline and diesel production.

Those companies that cannot meet the blending requirements must purchase credits, known as renewable identification numbers, or RINs, to meet their blending obligations.

After a Philadelphia refiner blamed the regulations for its bankruptcy, actions taken by the Trump administration have led the RINs market to plummet 84% year-to-date through Oct. 10, according to S&P Global Platts.

In April, a federal judge approved a settlement between the EPA and PES Holdings LLC that allowed the bankrupt refiner to shed a substantial portion of its RFS compliance obligations.

The EPA's granting of "hardship" compliance waivers to small refiners has benefited the broader refining industry.

Despite the reduced compliance burden, some refining executives are still wary of the policy.

CVR Refining LP President, CEO and Director David Lamp said during an Oct. 25 earnings call that the company had started blending B5, a blend of petroleum-based diesel containing 5% biodiesel, across all of its racks to increase internally produced RINs by 5% of its renewable volume obligation and that the company also has "several deals in the works" to reduce its RINs exposure.

"I would tell you that if I had a crystal ball, I could predict what RIN prices are going to be," Lamp said. "Frankly, I don't trust them. I don't trust the politics. I don't trust the law itself. ... And if they don't issue waivers like they did last year, I would say the price is going to go straight up, maybe not immediately, but … over time as the RIN bank goes away. I think it's kind of foolish to stick your head in the sand and say this issue is gone just because the RINs are cheap right now."

Lamp's comments come as the ethanol industry is in the midst of challenging the Trump administration's RFS waivers in federal court.

Some refiners continue to lobby for RFS policy changes, but during earnings calls they did not outline investments to mitigate the policy's effects.

"We're not fully where we think the market needs to go and where the administration needs to go as far as fixing the RFS problem, but we're continuing to work on it diligently," Marathon Petroleum Corp. Chairman and CEO Gary Heminger said during a Nov. 1 earnings call.

During the third quarter of 2017, Marathon said biofuel blending reduced the indicative gross margin of its refining business by $743 million, but a year later, executives declined to outline a specific benefit from lower RIN costs.

"We are not believers that RIN costs drive differential profitability within the refining system. We have a ... view that as RIN prices rise, it gets reflected in the crack, and on a net basis, the system is no better or worse off than where things are at. So I'm not sure we'd highlight an incremental benefit to the lower RINs costs," Marathon Senior Vice President and CFO Timothy Griffith said. "It certainly introduces a lot less noise into the market relative to what the real economic cracks are, but we would not identify any natural economic benefit in total to the system related to the lower prices."

Whichever direction biofuel policy takes, other refiners are investing in renewable fuels because they see them as a long-term part of the global fuel mix.

"If you step back and look at ethanol, it's going to be in the gasoline pool for a long time, and it's a core part of our strategy," Valero Energy Corp. Vice President of Alternative Fuels Martin Parrish said during an Oct. 25 earnings call. "We see corn ethanol as the most competitive source of octane in the world."

On Oct. 11, Green Plains Inc. announced it would sell three of its ethanol plants to Valero.

Parrish expects that growing U.S. ethanol exports and slowing domestic production growth will lead to improved margins for Valero's renewable fuels business, which the company recently decided to expand.

Valero executives pushed back on the notion that their decision to invest in renewable fuel production was related to the Trump administration's proposal to allow year-round sales of E15 — gasoline blends containing 15% ethanol — which the oil industry has vowed to fight in court.

"[It's] going to take a couple of years for that to work its way through the courts before you get a final answer [on its legality]," Valero's senior vice president of public policy and investor relations, Jason Fraser, said Oct. 25. "Put yourself into the shoes of one of those retailers who's got to spend money to be able to offer E15. You're going to spend money with the risk of having stranded capital because in a couple of years, the court may void [the rule]."



Oilfield service majors to limp into 2019 as North America land market struggles

Diversification helped oilfield service majors navigate through a difficult third quarter in North America land markets, but analysts see more downside risk for the sector in the last quarter and persistent challenges into 2019.

Bottlenecks in the Permian basin limited exploration and production in the prolific basin, impacting third-quarter earnings across the oilfield services sector.

Customer activity weakened during the third quarter as takeaway constraints in the Permian limited production growth, Schlumberger Ltd. CEO Paal Kibsgaard said during the company's Oct. 19 earnings call.

Halliburton Co. CEO Jeffrey Miller said Oct. 22 that the North America land market presented challenges in the third quarter amid a combination of off-take capacity constraints and customer budget exhaustion that led to less demand for its completion services.

Analysts said that the diversification of services offered by the two leading oilfield services companies sheltered them from larger negative impacts to quarterly earnings.

Schlumberger and Halliburton's international businesses performed well in the third quarter but could face challenges early in 2019.

Kibsgaard said Schlumberger's revenue from its international business, excluding Cameron, was up 4% sequentially to $4.6 billion in the third quarter. The strength of international markets, where the company expects "flattish" revenues in the fourth quarter, should outweigh any further challenges in the North America land market, the CEO said.

Halliburton saw international revenue in the third quarter climb 5% sequentially to $2.4 billion, and Miller said he is excited about the international markets in 2019. "It's a bit of a mixed bag in the sense that there are going to be markets like Asia-Pacific and Europe, Africa, Eurasia, that, in my view, may recover more so, pretty strongly on a percentage basis, just given where they started," Miller said. "But there's other parts of the market, all in Middle East, that have been fairly resilient throughout the downturn."

On its third-quarter call, Halliburton guided fourth-quarter earnings per share to a range of 37 cents to 40 cents, "well below consensus of 48 cents," analysts with B. Riley FBR said in an Oct 24 note. The company based its outlook on the collective impact of bottlenecks and budget exhaustion not only in the Permian, but also the Marcellus/Utica and DJ Basin. Schlumberger's Kibsgaard said its North America land revenue and earnings per share will be down in the fourth quarter, and the level of the decline will be a function of how severe the shutdowns are going to be in November and December.

The reasons for the headwinds in North America around takeaway issues and budget constraints were well understood by the market, but the pace of declines implied by the guidance from the two industry leaders likely caught some by surprise, said West Carlyle, an analyst with Evercore ISI. "The fact that the industry will see extended breaks with some starting before Thanksgiving mean that customer activity levels will decline for the last six weeks of the year and makes visibility challenging with pricing and utilization falling in the spot market," he said in an Oct. 22 note.

Halliburton expects these challenges to ease through 2019. In addition to a Permian re-acceleration, Halliburton expects to see bullish budgets for the Eagle Ford, Bakken, Marcellus/Utica and DJ Basin. FBR agrees with Hallburton management's view "of the transient nature of and resolution timing of the challenges," analyst Thomas Curran said Oct. 24.

FBR revised Halliburton EBITDA and earnings per share outlooks for 2018 and 2019 from $4.4 billion, or $1.98, and $5.3 billion, or $2.65, respectively, to $4.3 billion, or $1.86, and $4.8 billion, or $2.27, and set their 2020 outlook at $5.9 billion, or $3.32. Evercore analysts lowered Halliburton 2019 earnings per share estimate to $2.00, while CitiGroup analyst Andrew Scott said the bank lowered first-quarter 2019 earnings per share estimate for Halliburton to 39 cents and fiscal year 2019 to $2.04. A double-digit decline in fracking activity drove the bank to "take a hatchet" to its fourth-quarter earnings per share outlook to 37 cents to 40 cents, while the international business should be up modestly, Scott said.

Schlumberger said the company's international businesses would see 10% top-line growth in 2019 with national oil companies leading the charge on spending and the fastest growth rates for Latin America, sub-Saharan Africa and Asia. It also expects a continued climb in deepwater drilling activity, following an expected 8% rise this year, as well as help from pricing improvements.

FBR lowered its 2018 and 2019 EBITDA and EPS outlooks for Schlumberger from $7.53 billion, or $1.73, and $9.3 billion, or $2.55, to $7.22 billion, or $1.72, and $9.30 billion, or $2.45, on the net costs and disruptive impact of the company's broad, rapid rig mobilization internationally. For 2020 EBITDA is forecast at $10.60 billion, or $3.32 per share.

Curran said Schlumberger's third-quarter earnings call and annual sell-side roundtable reinforced the firm's thesis that outside of North America, the company is pivoting from a focus on investing and mobilizing to executing and harvesting. This "rest of the world," or non-North America land market, makes up 70% of Schlumberger's revenue. FBR expect Schlumberger to generate "a robust 2018-20 [free cash flow] trajectory and to return meaningful portions of it to shareholders."

Baker Hughes a GE company made strides developing its international presence to compete with the larger names in the international markets and said in its Oct. 30 earnings call that its smaller exposure to North America land fracking helped shield its earnings in the third quarter.

Jefferies analysts said Oct. 9 that Baker Hughes has plausibly gained a little share in oilfield services with non-North American market revenues flat in the first half compared to the second half of 2017, when compared with Halliburton and Schlumberger. "We don't doubt that [Baker Hughes] is pricing aggressively as it explicitly targets market share, although it feels far more consistent with peers' behavior through cycles than not," Jefferies said.

Jefferies lowered its 2019 earnings per share outlook for Baker Hughes to $1.45 from $1.65, and trimmed its 2020 estimate to $2.15 from $2.65. "That said, we model just under $4 per share in 2022 with the assumed later cycle contribution and assuming about 40% incrementals," the analyst said. Guggenheim Securities analysts said they expect all four of Baker's segments to contribute to growth in 2019 that should drive 11% and 29% growth in revenue and EBITDA, respectively.

For National Oilwell Varco Inc., its rig systems business suffered third-quarter losses as customers limited spending to only the most essential items in the third quarter, as a shrinking commodity price and subsequent activity decline led customers to limit capital spending.

Analysts with Tudor, Pickering Holt & Co. said Nov. 7 that during National Oilwell Varco's analyst day on Nov. 6 the company offered "some quantitative color" on its 2019 and three-year outlook. Amid "lots of assumptions," fiscal-year 2019 EBITDA was bracketed in $1.0 billion to $1.3 billion range, while Tudor Pickering Holt & Co. said its range was already around the midpoint, "which could be more like $1.8 billion to $2.5 billion a few years down road."

Barclays analyst David Anderson maintained National Oilwell Varco with an Equal-Weight and lowered the price target from $44 to $40. Raymond James analyst Praveen Narra maintained the company with an Outperform and lowered the price target from $55 to $45, and CitiGroup analyst Scott Gruber maintained National Oilwell Varco with a Neutral and lowered the price target from $48 to $40.

While the market remains challenging right now, the underlying trends still look positive for 2019, the Evercore analysts said. "Customer budgets will reset in 2019 with a backdrop of stronger commodity prices especially compared to where they entered 2018. The DUC count continues to rise which provides a backlog for demand when it gets worked down. Lastly takeaway capacity will expand and customer urgency will come back. Also the international recovery continues to emerge," the analysts said.



Strong shale output drives major US oil producers' earnings to multiyear highs

Following misses in the second quarter, many U.S. oil majors such as Exxon Mobil Corp. and Chevron Corp. saw third-quarter earnings soar to their highest levels in four years as oil prices remained strong and production, much of it from shale, increased.

After sinking in the second quarter to a multiyear low, Exxon's total output rebounded in the third quarter to 3.8 million barrels per day, up 4% on the quarter but still 2% below the same period in 2017. Third-quarter liquids output climbed 6% as growth in North America more than offset higher downtime.

Exxon's third-quarter shale oil output from the Permian Basin was up 57% on the year due to the ramp-up to the current 38 rigs in the Midland and Delaware basins. Exxon's third-quarter Permian production was up 170,000 barrels of oil equivalent per day, or 11%, on the quarter.

During the third quarter, Exxon's cash flow from operations and asset sales was $12.6 billion. Third-quarter cash flow from operating activities of $11.1 billion was the highest since the third quarter of 2014, the company said.

Separately, Chevron's shale production during the third quarter was 338,000 barrels per day in the third quarter. "Shale and tight production increased 155,000 barrels per day, primarily due to growth in the Midland and Delaware basins in the Permian where production grew by 80% from a year ago," Chevron CFO Patricia Yarrington said during a Nov. 2 earnings call.

Calif.-based Chevron continues to bet on rising returns from its Permian investments, with production levels trending about one year ahead of the guidance provided in March when executives announced plans to expand the overall upstream fleet and improve cash flow


"Chevron's rising production volumes and greater proportional exposure to oil and oil-linked LNG pricing really shined through in its third quarter results," Moody's Senior Vice President Pete Speer said. "The company generated nearly $4 billion of free cash flow in the quarter, as its more upstream weighted business mix combined with its oil price exposure really differentiated Chevron's financial performance from its major integrated peers."

Chevron reported third-quarter earnings of $4.05 billion, or $2.11 per share, beating the S&P Global Market Intelligence consensus estimate of $2.06 per share.

Chevron's quarterly cash flow from operations was $9.6 billion, the highest it has been in nearly five years.

Ongoing healthy cash flow could allow Chevron to expand its $3 billion-per-year share buyback program, the company said. During the third quarter, Chevron spent $750 million on share repurchases. The company had not repurchased shares in several years, since around the time global crude prices began to crumble. Buying back existing stock generally makes the remaining shares more valuable.

Texas-based oil and gas producer ConocoPhillips reported adjusted net income for the third quarter of $1.6 billion, or $1.36 per share, far exceeding S&P Global Market Intelligence consensus estimate of $1.19 per share.

While a key driver was a settlement with Petróleos de Venezuela SA to fully recover an arbitration award of approximately $2 billion, ConocoPhillips also reported strong output during the third quarter that worked to lift its earnings.

In the third quarter, the company's output, excluding Libya, was 1.22 million barrels of oil equivalent per day, up 22,000 boe/d from the same period a year ago but below the S&P Global Market Intelligence consensus estimate for daily production of 1.24 MMboe/d.

In the Lower 48, production from the company's high-margin "big three" unconventional plays grew to 310,000 boe/d, a 48% increase year over year. Production from the big three unconventionals, which include the Eagle Ford Shale, the Delaware play and the Bakken Shale, is expected to grow more than 35% for the full year.

Fourth-quarter production is expected to be between 1.275 MMboe/d and 1.315 MMboe/d, reflecting the completion of seasonal turnarounds, growth from several conventional project startups and ongoing development in unconventional production, the company said.