The spread between the world’s two benchmark crude oil markers – Brent and WTI – is currently hovering at US$6/b. This is the widest gap between the two for a long while, first breaching the tight US$2/b spread range since 2015 in the run up to Hurricane Harvey as traders fretted that widespread refinery closures along the US Gulf would impact US crude consumption.
Those refineries have come back online, but the spread is still persisting. It is so large that India’s Reliance – an opportunistic buyer if there was any – bought a massive million barrel cargo of US crude oil last week. All across Asia, key buyers are taking advantage of this new arbitrage window to stock up on (cheaper) American crude, some for the very first time. Indian refiners – notably state refiners IndianOil, HPCL and BPCL – are leading the way, with buyers from South Korea, Japan, Thailand and Singapore also in the fray. Chinese activity is still minor, but one has to imagine they can’t be that far behind.
When the Brent-WTI spread hit its all time high at US$28/b in September 2011, there was a similar enthusiasm for US crude. Volumes then, however, weren’t readily available. The WTI discount to Brent then was because oil generated from the burgeoning US shale revolution was trapped in Cushing, Oklahoma – the main price settling point for WTI – at a time when global demand was soaring. In other words, the discount was due to the inability of sufficient WTI volumes to make it into the wider market. The oil was there, but midstream infrastructure to ship it to Houston and from there to the wider world, was inadequate. A rush to expand existing pipelines and build new ones – transportation by train was even used at one point to clear volumes – occurred, and when it did by 2014, the Brent-WTI spread had decreased. The lifting of the US crude export ban in 2015 narrowed things even further, to a range of US$2-3/b.
In 2017, that lack of infrastructure is no longer there. Supply has caught up with the ability to meet demand, and as US oil exports soared, WTI prices have closed the gap with Brent, which is used as the main international marker, including Middle Eastern grades. In such a competitive scenario, we would expect both benchmarks to move towards parity.
But even before Hurricane Harvey reared its head, the Brent-WTI spread was already growing. The circumstances this time are different. On the Brent side, there is a ‘fear premium’ being priced in; tensions in the Middle East – between Qatar and the rest of GCC, tensions between Iraq and its Kurdish province – have been raising the spectre of supply disruptions. More significant though is that on the WTI side, there is now once again an abundance of supply. But unlike before, that supply can make it to market. Which is why we are seeing such strong volumes of US crude exports. Some six million barrels are earmarked to be shipped from the US to Asia for November so far; up from usual monthly shipments of 2-3 million barrels. The cheap prices are enticing, but Asian refiners are being forced to look further afield for crude as OPEC and some non-OPEC sellers have been cutting availability as part of their supply freeze.
US crude exports reached an all-time weekly high at the end of September. That jump in demand should naturally reduce the spread. The Brent physical market is tight, meaning that Brent’s strength is not artificial but demand driven. A break towards US$60/b appears possible soon. But a look over the future curve indicates that the current Brent-WTI spread will persist through October 2018, having doubled since May 2017. This suggests that the sheer amount of supply coming out of the US will negate demand drivers to keep WTI significantly lower than Brent, where supply is a lot steadier.
That’s good news for Asian buyers, as the avenue of cheaper US crude remains open to them for far longer. With OPEC likely to extend, or even deepen, the supply freeze beyond the current deadline of March 2018, Brent-linked crude volumes will be in short supply. The distance from Houston to Yokohama, Singapore or even Paradip is vast - VLCCs have to go through the Suez as the Panama Canal is too narrow – but at current and projected spreads, well worth the distance.
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In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts year-over-year decreases in energy-related carbon dioxide (CO2) emissions through 2021. After decreasing by 2.1% in 2019, energy-related CO2 emissions will decrease by 2.0% in 2020 and again by 1.5% in 2021 for a third consecutive year of declines.
These declines come after an increase in 2018 when weather-related factors caused energy-related CO2 emissions to rise by 2.9%. If this forecast holds, energy-related CO2 emissions will have declined in 7 of the 10 years from 2012 to 2021. With the forecast declines, the 2021 level of fewer than 5 billion metric tons would be the first time emissions have been at that level since 1991.
After a slight decline in 2019, EIA expects petroleum-related CO2 emissions to be flat in 2020 and decline slightly in 2021. The transportation sector uses more than two-thirds of total U.S. petroleum consumption. Vehicle miles traveled (VMT) grow nearly 1% annually during the forecast period. In the short term, increases in VMT are largely offset by increases in vehicle efficiency.
Winter temperatures in New England, which were colder than normal in 2019, led to increased petroleum consumption for heating. New England uses more petroleum as a heating fuel than other parts of the United States. EIA expects winter temperatures will revert to normal, contributing to a flattening in overall petroleum demand.
Natural gas-related CO2 increased by 4.2% in 2019, and EIA expects that it will rise by 1.4% in 2020. However, EIA expects a 1.7% decline in natural gas-related CO2 in 2021 because of warmer winter weather and less demand for natural gas for heating.
Changes in the relative prices of coal and natural gas can cause fuel switching in the electric power sector. Small price changes can yield relatively large shifts in generation shares between coal and natural gas. EIA expects coal-related CO2 will decline by 10.8% in 2020 after declining by 12.7% in 2019 because of low natural gas prices. EIA expects the rate of coal-related CO2 to decline to be less in 2021 at 2.7%.
The declines in CO2 emissions are driven by two factors that continue from recent historical trends. EIA expects that less carbon-intensive and more efficient natural gas-fired generation will replace coal-fired generation and that generation from renewable energy—especially wind and solar—will increase.
As total generation declines during the forecast period, increases in renewable generation decrease the share of fossil-fueled generation. EIA estimates that coal and natural gas electric generation combined, which had a 63% share of generation in 2018, fell to 62% in 2019 and will drop to 59% in 2020 and 58% in 2021.
Coal-fired generation alone has fallen from 28% in 2018 to 24% in 2019 and will fall further to 21% in 2020 and 2021. The natural gas-fired generation share rises from 37% in 2019 to 38% in 2020, but it declines to 37% in 2021. In general, when the share of natural gas increases relative to coal, the carbon intensity of the electricity supply decreases. Increasing the share of renewable generation further decreases the carbon intensity.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
Note: CO2 is carbon dioxide.
GEO ExPro Vol. 16, No. 6 was published on 9th December 2019 bringing light to the latest science and technology activity in the global geoscience community within the oil, gas and energy sector.
This issue focusses on oil and gas exploration in frontier regions within Europe, with stories and articles discussing new modelling and mapping technologies available to the industry. This issue also presents several articles discussing the discipline of geochemistry and how it can be used to further enhance hydrocarbon exploration.
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Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b
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