The United States exported 7.3 million barrels per day (b/d) of crude oil and petroleum products in the first half of 2018, when exports of crude oil and hydrocarbon gas liquids (HGL) set record monthly highs. Crude oil surpassed HGLs to become the largest U.S. petroleum export, with 1.8 million b/d of exports in the first half of 2018. U.S. exports of crude oil, HGLs, and motor gasoline grew in the first half of 2018 compared with the same period in 2017, while distillate exports decreased 84,000 b/d (Figure 1).
U.S. crude oil exports increased by 787,000 b/d (almost 80%) from the first half of 2017 to the first half of 2018 and set a new monthly record of at 2.2 million b/d in June. Destinations in Asia and Oceania were the largest recipients of U.S. crude oil exports in the first half of 2018, and U.S. crude oil exports to China more than doubled—increasing by 193,000 b/d—from the first half of 2017. U.S. crude oil exports to South Korea and India also increased significantly during this period, up 81,000 b/d and 72,000 b/d, respectively.
Europe was the second-largest market for U.S. crude oil exports, receiving 555,000 b/d in the first half of 2018. U.S. crude oil export volumes to Europe are more equally distributed than in other regions. Italy, the United Kingdom, and the Netherlands, each received more than 120,000 b/d in the first half of 2018. Canada was the only major U.S. crude oil export destination where exports decreased somewhat, down 13,000 b/d in the first half of 2018 compared with the same period in 2017 (Figure 2).
HGLs were the second-largest petroleum export from the United States in the first half of 2018 at 1.6 million b/d. Destinations in Asia and Oceania were also the primary recipients of U.S. HGLs at 618,000 b/d in the first half of 2018. The region’s main importers were Japan, South Korea, China, and India, many of which have expanded petrochemical facilities that import U.S. HGLs as a feedstock. The second-largest regional destinations for U.S. HGL exports in the first half of 2018 were Canada and Mexico in North America, which received a combined 453,000 b/d in the first half of 2018 (Figure 3). U.S. HGL exports also set a new monthly record in the first half of 2018 at 1.7 million b/d in May 2018.
In the first half of 2018, the United States exported 1.3 million b/d of distillate, primarily to destinations in Central and South America, with Brazil and Chile as the two largest destinations, receiving 131,000 b/d and 114,000 b/d, respectively. The decline in U.S. distillate exports in the first half of 2018 compared with the first half of 2017 is mostly the result of lower exports to a number of destinations in Central and South America and in Europe. However, U.S. distillate exports are typically higher in summer months, most of which occur in the second half of the year. The largest single destination for U.S. distillate exports in the first half of 2018 was Mexico at 289,000 b/d (Figure 4). Despite being the third-largest U.S. petroleum export, U.S. distillate exports go to the largest number of destinations—as 49 different destinations received at least 1,000 b/d in the first half of 2018.
The United States exported 913,000 b/d of motor gasoline in the first half of 2018, an increase of 144,000 b/d compared with the same period in 2017. Mexico accounted for more than half of U.S. motor gasoline exports in the first half of 2018, the largest single-destination concentration for any U.S. petroleum export (Figure 5). Years of under investment in Mexico’s refineries, combined with a mismatch between the type of crude oil produced locally and the type of crude oil Mexico’s refineries were designed to process, has resulted in low refinery utilization rates. Low refinery utilization has resulted in increased imports of motor gasoline and other petroleum products, from the United States. Mexico’s gasoline consumption ranges from 780,000 b/d to 800,000 b/d based on recent history. In the first half of 2018, U.S. gasoline exports to Mexico accounted for more than 60% of the gasoline consumed in Mexico.
U.S. average regular gasoline price decreases, diesel price increases
The U.S. average regular gasoline retail price decreased less than 1 cent from last week to $2.82 per gallon on September 3, 2018, up 15 cents from the same time last year. West Coast prices increased nearly two cents to $3.33 per gallon, and East Coast and Rocky Mountain prices each rose over one cent to $2.78 per gallon and $3.01 per gallon, respectively. Midwest prices fell nearly three cents to $2.73 per gallon and Gulf Coast prices decreased two cents to $2.55 per gallon.
The U.S. average diesel fuel price increased over 2 cents from last week to $3.25 per gallon on September 3, 2018, 49 cents higher than a year ago. Midwest prices increased nearly four cents to $3.19 per gallon, Gulf Coast prices rose over three cents to $3.04 per gallon, West Coast prices increased more than two cents to $3.74 per gallon, and East Coast prices increased over one cent to $3.24 per gallon. Rocky Mountain prices were unchanged, remaining at $3.36 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 2.0 million barrels last week to 73.4 million barrels as of August 31, 2018, 9.7 million barrels (11.7%) lower than the five-year (2013-2017) average inventory level for this same time of year. Midwest, Gulf Coast, and East Coast inventories increased by 1.2 million barrels, 0.5 million barrels, and 0.3 million barrels, respectively, while Rocky Mountain/West Coast inventories fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 3.9% of total propane/propylene inventories.
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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.