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Nick Cunningham

Nick Cunningham

Nick Cunningham is an independent journalist, covering oil and gas, energy and environmental policy, and international politics. He is based in Portland, Oregon. 

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U.S. Shale’s Dirty Secret


U.S. shale is surging, threatening to take even more market share away from OPEC. But the prospect of U.S. oil edging out barrels from the Middle East is not nearly as simple as it might seem.

Oil coming from the major shale plays in the U.S. is light and sweet, while a lot of oil coming from OPEC is medium or heavy, and often sour. A lot of refining capacity along the U.S. Gulf Coast, built up over years and decades, is equipped to handle heavier forms of oil. Before the shale revolution, refiners made their investments in downstream assets assuming the oil they would be using would come from places like Saudi Arabia and Venezuela.

Lighter shale oil is perfectly fine for making gasoline, but not the best for making diesel and jet fuel. Medium and heavy oil is needed for that.

But refiners have a tidal wave of light sweet oil on their hands, perhaps too much. The U.S. refining industry could max out its ability to swallow up light sweet oil from the shale patch, as the FT reports, particularly as U.S. shale drillers are expected to add upwards of 4 million barrels per day (mb/d) over the next five years.

Meanwhile, heavy crude production has waned as of late, with sharp declines in output in Venezuela and Mexico in the past few years. Shipments from Canada face a bottleneck because of fixed pipeline capacity. The result has been a somewhat tighter market for heavy oil, which refiners want to process into jet fuel and diesel.

In the years ahead, demand for gasoline could start to slow down as vehicles become more efficient and EVs start to gain more market share. Meanwhile, diesel demand has grown much faster, and will likely jump in 2020 as new regulations on dirty fuels from the International Maritime Organization take effect. That could force the shipping industry to switch from residual fuels to diesel, perhaps adding as much as 2 mb/d of demand for diesel, the FT reports.

In other words, volumes of lighter oil suited for gasoline production are soaring while production of medium and heavy oil used for diesel is flatter, even as diesel demand is poised to grow quickly. And refining capacity capable of handling light oil might not be up to the task. Related: Is Another Oil Price War Looming?

That could present some problems for refiners, some analysts say. “The dirty secret of U.S. shale oil is not many people want it,” Bill Barnes of Pisgah Partners, an energy project development consultancy, told the FT. “It’s wrong to say the U.S. can add 1m-plus barrels a day of production capacity a year and it will immediately find a home in the world’s refining system.”

Just because shale production is skyrocketing does not mean that refiners want the oil. Franco Magnani, the head of trading at Eni, told the FT that the company won’t rush out and by shale oil because its refineries were not made for that type of oil. “It could be a top-up in certain situations but not really a base diet [for Eni’s refineries],” Magnani told the FT. “[Shale’s] very light so either you have a refinery that’s geared towards that but maybe then it’s too light even for that. Or you use it only in very specific situations.”

Not everyone agrees, noting that in a 100-mb/d oil market, adding 1 or 2 mb/d of light oil is manageable. The problem with that notion is that only a fraction of the global refining industry can handle digest additional barrels of light oil. After excluding the U.S. refining system, which is reaching its limits, the market for light oil is closer to 15 mb/d, the FT reports.

The result could be that shale producers might have to accept discounts for their product in the next few years if refiners balk at purchasing every additional barrel of light oil.

According to a recent study from Wood Mackenzie, roughly three-quarters of the additional oil expected to come from U.S. shale will have to go overseas because U.S. refiners will be maxed out on light oil. Related: How Will OPEC React To Soaring Shale Production?

Others agree. “There will still be a sizable surplus of lightweight crude,” Rob Smith, director of IHS Markit’s oil markets and downstream group, told Reuters. He predicts U.S. shale will add 4 mb/d of new supply by 2023, a volume that cannot be taken up by existing refineries along the Gulf Coast. WoodMac estimates that refiners will only be able to take up about 1 mb/d of extra 4 mb/d through 2023. The rest will have to be exported.

The flip side is that the shortage of light oil refining capacity might spark new investment in new facilities. ExxonMobil just announced plans to double its light oil refining capacity along the Gulf Coast, an investment specifically made because of the surplus of light oil in Texas. The expansion would take place at Exxon’s Beaumont and Baytown refineries in Texas and Louisiana. “It’s really a full Gulf Coast upgrade,” Senior Vice President Jack Williams told Wall Street analysts last week, according to Reuters. “We know this is going to be a long-term resource,” he said.


Ultimately, a surplus of light oil could be a problem for shale drillers. Sharper discounts could challenge the economics of adding new supply, perhaps throwing up obstacles to growth. That could challenge the industry’s ability to meet the aggressive expectations that so many forecasters have laid out.

By Nick Cunningham of Oilprice.com

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  • Jeffrey J. Brown on March 15 2018 said:
    My "Butcher shop" analogy:  It's as if when you ask a butcher for the price of beef, he gives you the price of steak, but if you ask him for how many pounds of beef he has on hand, he gives you total supply of steak, roast and hamburger, i.e., the price indexes for oil do not correlate to the supply numbers. 

    When we ask for the price of oil, we get the price of actual crude oil (generally defined as crude oil with an API Gravity of 45 or less), but when we ask for the supply of oil, we get the volume of crude oil plus partial substitutes—condensate, natural gas liquids and biofuels. Note that the maximum API gravity for WTI crude oil is 42 Degrees.

    And I've always thought that the following chart regarding 16 grades of global crude oils is compelling.  It shows what global refineries were designed to process, and what they need in order to meet distillate demand:


    And my sketch showing the growing post-2005 gap between the global gas production and global Crude + Condensate (C+C) production curves:


    The global supply of C+C, what the EIA and other agencies call "Crude oil," has been getting increasingly lighter since 2005, and this is an ideal time to find and develop a series of high quality shallow oil reservoirs containing actual crude oil.
  • paul on March 15 2018 said:
    Eh! Canadian heavy crude up to 39 today, nothing the Xtra Large Keystone cant help alleviate. Denver gas 2.21 refined at Suncor from cheap Ca crude. Thanks, eh.
  • James Eberle on March 15 2018 said:
    Mr. Cunningham. Please investigate the work of Art Berman, a respected petroleum geologist and prospect generator with 40 years experience in the field. You will then develop a deeper appreciation for the overly optimistic future of tight oil. As he has said; the shale “boom” is really a “retirement party” for the oil industry.
  • Mamdouh G Salameh on March 16 2018 said:
    May I congratulate you, Mr Cunningham, for an objective article with good analysis.

    Please permit me to indulge myself by saying that since the shale oil revolution ten years ago, there has been so much hype about it that there are no secrets, dirty or clean, about it left.

    It is , however, no secret that shale/tight oil is so light that it is overwhelmingly used and sold to refineries around the world for blending with heavier crudes. Therefore, it can’t compete with OPEC and Russian crudes in the global oil market and if this is the case then it can’t displace any oil exports from OPEC or Russia.

    Claims by the EIA about rising US oil output mask the fact that the EIA production figures include a minimum of 2 million barrels a day (mbd) of natural gas liquids and plant gases such gases as ethane, propane, butane and pentanes which don’t qualify as crude oil and condensates in its crude oil count. The real question is whether natural gas plant liquids can be sold as oil on the world market. The answer is an emphatic “No”. In fact, major oil exchanges accept neither natural gas plant liquids nor lease condensates as satisfactory delivery for crude oil. And if major exchanges don’t accept natural gas liquids as crude oil, then they are not crude oil.

    Based on the above, we reach the conclusion that claims by the EIA and the IEA about increases in US oil output and about the United States overtaking Saudi Arabia and Russia this year or next year to become the world’s oil producer are fake news.

    If, however, there are any dirty secrets left about shale oil, they must relate to reports of seismic drilling for shale oil causing tremors and contaminating deep underground water resources.

    Dr Mamdouh G Salameh
    International Oil Economist
    Visiting Professor of Energy Economics at ESCP Europe Business School, London
  • Kr55 on March 16 2018 said:
    Other dirty secret is that most shale players are still losing money at these prices and depend on more and more borrowing and share issues to grow production.

    And they have already maxed out the capacity in the USA for light oil. Most shale producers have been saying for many quarters that any new production they add has to get shipped off.
  • Randy Verret on March 16 2018 said:
    As usual, good analysis! I would say that this is just another factor with Shale oil that further bolsters the position that U.S "energy independence" is a mirage. That line of reasoning is no more valid than the statement that the U.S can be "100% renewables by 2050." We are energy INTERDEPENDENT in a global commodity market...
  • Norman Pagett on March 16 2018 said:
    the use of heavy or light oils, their respective refineries and so on is irrelevant

    during the coming decade, if not sooner, we will be hit by the reality that oil is unaffordable whatever type it is, or wherever it comes from.

    Oil costs too much to get hold of. We are spending/investing increasing amounts to go deeper and deeper for less and less oil---we are now 'discovering' only about 10% of the amount of oil we are using each year

    a business that burns through 90% in excess of its income is bankrupt---there can be no other word for it

    this explains it more clearly:

  • D R Pearson on March 16 2018 said:
    The lack of refineries to process the light shale oil is going to help Exxon after they expand their refineries in order to refine the light grade crude which they plan on increasing their production to 600 kbopd. This is where it is advantageous to have an upstream and downstream segment to your business.

    My only question will be how long will it take to pay out the refinery expansion since shale oil production isn't suppose to be a longtime resource due to limited EURs for the shale oil plays. The EUR question is debatable, but I assume Exxon has included the time-frame issue for the light shale oil plays, and/or they are engineering the new refinery expansion so that it can be flexible for multiple API grades of crude (if that is even doeable). Regards.
  • Jason on March 16 2018 said:
    Great analysis Nick.

    However, I would bet that the oil industry knows this and they will be making changes to their refineries to be able to accept more shale oil. At any given time their are multiple units within refineries that are in turnaround and if they have a means of getting shale oil to the refinery they will put the engineers to work on developing a way to process it.

    With dozens of planned pipeline projects across the country that will take shale oil to refineries and export terminals, I’m sure that any increased in shale oil production will find a place to go.
  • Jerome on March 16 2018 said:
    You could have tweeted all that mattered.

    "Xtra shale b light sweet crude. Need new refinery b4 market wants it."
  • Barry on March 24 2018 said:
    "Class, can we hold up our hands and show a vote of confidence for the investors who option geo-thermal technology for as-yet un-redeveloped, shut-in and abandoned wells in Pa., offshore La., Miss., and LOTS of other places?"
    "Better till, can we vote for replacing chemical fracking with geo-thermal fracking as soon as possible, enjoying the additional energy production that will continue from using geo-thermal technology for electricity production that continues long after the fracking has ceased?"
    Ongoing EPA and DOE research potentially validates the evolution of geo-thermal technology economics, AND environmental "sustainable vs. sunk costs" calculations. in a variety of energy development and processing plays.
    Additionally, a research project concept preliminarily indicates that excess geo-thermal used to power "territorial-meaning development area-wide- refinery operations" offers a potential highest value result to this type of integrated operation.
  • PaulFuddie on March 25 2018 said:
    With all the wild speculative investments in shale, corn ethanol, light water commercial nuclear reactors, Thorium 232 gen IV passive cooling reactors and so on, what's so wrong with a new kind of fusion? such as solar and or wind powered destructive distillation plants using coal? It was good enough during WW II for making petrol
    can't we tweak old technology a bit here?

Leave a comment

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