Global energy markets have been in a rebalancing process since mid-2014. Following the Great Recession, advancements in petroleum drilling techniques, coupled with accommodative capital markets, fostered significant growth in U.S. crude oil and lease condensate production volumes. But after five years of double-digit production growth, this growth rate proved unsustainable against the slowing global demand. While the daily global crude oil production surplus has roughly halved since the end of 2015, the market remains in surplus. From an estimated peak surplus of roughly 2 million barrels per day during the fourth quarter of 2015, the U.S. Energy Information Administration (EIA) expects second quarter 2016 daily production of roughly 95.8 million barrels per day to have outpaced global consumption by about 1 million barrels per day, adding daily to global stocks. Supply/demand fundamentals have been in surplus for more than 2.5 years now, and without demand growth to absorb excess supply, the commodity sits idly in storage. Global crude oil stocks are now setting all-time record levels of 3.073 billion barrels, as last estimated by EIA in May 2016.
With this global supply glut now coinciding with record low shipping rates, the topic of “floating storage” has become dinner-table fodder for energy executives. Following its extraction, crude oil is transported to a destination and may be refined immediately or put into storage. While dozens of companies provide estimates on the amount of crude stored in traditional on-land tanks around the world, only a handful peel back the next layer to dig into tanker ships being used for storage as opposed to pure transportation.
Looking to get more insight into this new trend, we recently sat down with Matt Smith, the director of commodity research at ClipperData, a vendor of proprietary commodities cargo data and analytics. ClipperData’s focus is on reporting global flows of crude oil and petroleum products to a client base consisting largely of energy producers, refiners, trading companies and hedge funds. By capturing data on approximately 90 million barrels a day of cargo that is loaded and unloaded at port terminals around the world, the company aims to decipher the who, what and where of petroleum markets – living up to its motto of “know the cargo” – and to provide a balanced, data-driven outlook. During our conversation, we zeroed in on one of ClipperData’s hallmarks: tracking and reporting on crude oil stored in oceangoing vessels and tankers, or floating storage, and the implications for supply and demand.
Brown Brothers Harriman: ClipperData keeps its finger on the pulse of crude markets. What is data in the floating storage market currently telling you?
Matt Smith: Generally speaking, the world is awash in crude oil, and we can look to floating storage as an indicator of the regional balances between supply and demand. Floating storage itself can’t be globally generalized because the drivers behind it are very geographically dependent. What causes crude oil to build up in Asia may be different from what causes it to build in the Gulf Coast. Even throughout Asia there are stark differences, with two good examples being the ports of Qingdao and Singapore. Qingdao is an unloading port for much of China’s burgeoning independent refining industry, where demand growth has far outpaced other global refining regions during the past year. A buildup in tankers offshore Qingdao is more of a bullish signal on the Chinese refining industry and means there is a lot of crude queuing to come onshore for refining.
Singapore, on the other hand, is Asia’s central physical crude trading hub and not a focus of regional refinery demand. A buildup in crude tankers offshore there tends to be a more bearish indicator for Asian demand because vessel movement data tells us that the country is more of a stopover point than a port of final destination. Recently, more tankers originating in the Middle East and Africa seem to be “parking” in Singapore for a period of time while they sort out final buyers and unloading terminals.
BBH: What about that signals softer demand, as opposed to an infrastructure bottleneck as in Qingdao?
MS: We see a buildup in tankers offshore Singapore as more likely to be unsold cargoes. Offshore Singapore, vessels that are stationary for seven days or more must navigate to a maritime “waiting” area, meaning any vessels anchored in a specific area of water off the country’s coast have been idle for at least a week. Using tracking data, we identify stationary crude vessels and can then infer roughly how much crude is floating offshore Singapore. Companies chartering vessels pay on a per diem rate, so it’s quite likely that if the vessel’s contents were sold, the ship itself would be sailing toward its port of destination. To us, it is reasonable to assume that parked crude oil is more likely than not still looking for a buyer. Since the start of the year, Singaporean floating storage has been between 20 million and 35 million barrels, holding more to the high end of that range. We interpret that as a bearish signal on Asian demand.
BBH: You mentioned that tankers idling around the port of Qingdao in northern China point more toward an infrastructure bottleneck that signals demand growth from China’s northerly refining industry. This sounds like a more recent phenomenon for Asian demand.
MS: It is, and it’s reshaping China’s appetite for crude. Through July of this year, we have seen crude oil imports into Qingdao up 50% compared with year-ago levels. For the most part, these imports are going to a specific refining segment: privately owned, midsize refiners in China (called “teapot refiners” in the industry). They are now importing about 15% of the country’s daily demand for crude. The Chinese government liberated its refining industry earlier this year in a bid to stir more refining competitiveness in the country’s internal energy market. The party has granted 27 import licenses to teapot refiners in the past year alone. With an overall environment of political support for independent refining, China is easing regulations and becoming more of a free market participant. It has been granting export licenses, too, which we are seeing in middle distillate export data. After receiving licenses, the teapot refiners went to market in early spring 2016 when crude prices were low and did some rampant bargain hunting, pulling in cargoes at low prices for late spring and early summer delivery. That’s why crude is piling up offshore Qingdao. Recently we have seen this volume drop off considerably, which is a bearish signal; it indicates that demand is dropping off from the teapot refiners.
China appears to be stockpiling at a fervent pace, but there is limited storage capacity built out. By the most optimistic of estimates, the country appears to be running out of space given that inventory build is close to 150 million barrels this year. We have been waiting for Chinese oil imports to drop off considerably, and we are starting to see that reflected in our import data; inflows in July dropped to their lowest level since January and are likely to continue to remain under pressure. China is the biggest bearish wildcard from our perspective.
Even so, emerging markets still lead the charge in demand growth. The composition of that growth is changing, though. There is particularly interesting data coming out of India, which is now in the process of taking the lead from China in terms of all-in demand growth rates for petroleum products.
If we look beyond crude into the types of refined products being consumed, the story gets more interesting. Demand in China is growing in pockets; gasoline demand has been strong, driven by vehicle sales, while diesel demand is contracting for a third consecutive year, as it tends to be used predominantly by heavy machinery for industrial uses. China’s economy is shifting from one driven by industry and exports to one driven by domestic demand. The country’s middle class is still growing in the face of a decelerating industrial economy; they are still buying their first automobile or upgrading vehicles to SUVs. We can see in our data that as teapot refiners produce more products, some of that gasoline is being absorbed by rising demand, whereas there has been a more extreme excess of diesel created, leading to record exports.
Pockets of demand growth in China contrast with India, where demand growth appears to be more broad-based across energy products: gasoline, diesel, fuel oil and LPG.1 Accordingly, we have seen India’s crude imports so far rise more than 9% higher than last year. The country is surpassing Japan as the third-largest crude consumer globally. All said, India’s demand growth is starting to look similar to China a few years ago. While the overall theme of “developing markets will drive demand” hasn’t changed, the makeup of that demand is changing.
BBH: What other interesting changes are you seeing in crude oil?
MS: The market is still saturated. According to primary sources, Saudi Arabia reached a new production record in July. It’s not unusual for Saudi production to ramp up in summer due to power generation demand, but the combination of its record production levels and export volume are juxtaposed vs. its comments about supporting market rebalancing and a production freeze. We can see this as clear as day in our data. As a collective group, the Middle East OPEC members have increased exports by 3.3 million barrels per day since the beginning of last year, up 20% to 18.5 million barrels. Saudi Arabia, Iraq and Iran have led this increase.
Otherwise, elevated stocks remain core to the rebalancing story. Even if the market does not come into balance, we will have to work through a record overhang of crude oil and products. We see it clearly in domestic inventory levels – U.S. crude and product inventories set a new record of 1.39 billion barrels in the second week of August. That number has risen by 200 million barrels in the past 17 months alone. Due to the global oversupply, there have been some fairly heavy physical discounts to be had internationally; accordingly, we are seeing East Coast refiners changing their buying habits.
With shipping rates at historic lows, our data is showing that it is more economical to import crude from the west coast of Africa than to rail domestic production to the Eastern Seaboard refining areas. Recently we have seen West African imports to the U.S. East Coast displace crude-by-rail, or CBR, with railcar shipments to the East Coast falling about 45% over the past year. CBR economics depend largely on the relationship between international and U.S. crude oil prices. Since the export ban was lifted, domestic crudes are no longer as steeply discounted relative to imported oils, which is why imports are starting to displace CBR. We are able to track the decline in CBR to the U.S. East Coast because Bakken crude is loaded onto barges to complete the final part of its journey.
BBH: Thanks, Matt, for sharing some of your insights with us.
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1 Liquefied petroleum gas.