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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A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.
That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.
That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.
Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.
Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?
Expectations at the 176th OPEC Conference
Global liquid fuels
Electricity, coal, renewables, and emissions
Source: U.S. Energy Information Administration, U.S. liquefaction capacity database
On May 31, 2019, Sempra Energy, the majority owner of the Cameron liquefied natural gas (LNG) export facility, announced that the company had shipped its first cargo of LNG, becoming the fourth such facility in the United States to enter service since 2016. Upon completion of Phase 1 of the Cameron LNG project, U.S. baseload operational LNG-export capacity increased to about 4.8 billion cubic feet per day (Bcf/d).
Cameron LNG’s export facility is located in Hackberry, Louisiana, next to the company’s existing LNG-import terminal. Phase 1 of the project includes three liquefaction units—referred to as trains—that will export a projected 12 million tons per year of LNG exports, or about 1.7 Bcf/d.
Train 1 is currently producing LNG, and the first LNG shipment departed the facility aboard the ship Marvel Crane. The facility will continue to ship commissioning cargos until it receives approval from the Federal Energy Regulatory Commission to begin commercial shipments. Commissioning cargos refer to pre-commercial cargo loaded while export facility operations are still undergoing final testing and inspection. Trains 2 and 3 are expected to come online in the first and second quarters of 2020, according to Sempra Energy’s first-quarter 2019 earnings call.
Cameron LNG has regulatory approval to expand the facility through two additional phases, which involve the construction of two additional liquefaction units that would increase the facility’s LNG capacity to about 3.5 Bcf/d. These additional phases do not have final investment decisions.
Cameron LNG secured an authorization from the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as to countries with which the United States does not have Free Trade Agreements (non-FTA countries). A considerable portion of the LNG shipments is expected to fulfill long-term contracts in Asian countries, similar to other LNG-export facilities located in the Gulf of Mexico region.
Cameron LNG will be the fourth U.S. LNG-export facility placed into service since February 2016. LNG exports rose steadily in 2016 and 2017 as liquefaction trains at the Sabine Pass LNG-export facility entered service, with additional increases through 2018 as units entered service at Cove Point LNG and Corpus Christi LNG. Monthly exports of LNG exports reached more than 4.0 Bcf/d for the first time in January 2019.
Source: U.S. Energy Information Administration, Natural Gas Monthly
Currently, two additional liquefaction facilities are being commissioned in the United States—the Elba Island LNG in Georgia and the Freeport LNG in Texas. Elba Island LNG consists of 10 modular liquefaction trains, each with a capacity of 0.03 Bcf/d. The first train at Elba Island is expected to be placed into service in mid-2019, and the remaining nine trains will be commissioned sequentially during the following months. Freeport LNG consists of three liquefaction trains with a combined baseload capacity of 2.0 Bcf/d. The first train is expected to be placed in service during the third quarter of 2019.
EIA’s database of liquefaction facilities contains a complete list and status of U.S. liquefaction facilities.