In the first half of 2019, U.S. exports of crude oil increased to average 2.9 million barrels per day (b/d), an increase of 966,000 b/d from the first half of 2018. Also in the first half of 2019, U.S. crude oil exports set a new record-high monthly average of 3.2 million b/d in June 2019 (Figure 1). The number of U.S. crude oil export destinations also continued to grow, and now exceeds the number of U.S. crude oil import sources.
Asia was the largest regional destination for U.S. crude oil exports—1.3 million b/d in the first half of 2019—followed by destinations in Western Europe, which received 824,000 b/d. U.S. crude oil exports to North America, which almost exclusively go to Canada (the largest single destination for U.S. crude oil exports globally) did not change much from the first half of 2018 to the first half of 2019, averaging 458,000 b/d.
U.S. crude oil exports to Asia grew significantly in the first half of 2019, up 472,000 b/d (58%) compared with the same period in 2018, despite a large decrease in exports to China. U.S. crude oil exports to China in the first half of 2019 averaged 248,000 b/d (64%) less than the same period last year. This decrease largely reflects continuing trends from the second half of 2018 when U.S. crude oil exports to China decreased significantly.
Increased U.S. crude oil exports to other destinations in Asia offset the drop in volumes to China. U.S. crude oil exports to South Korea increased 278,000 b/d (246%), exports to India increased 154,000 b/d (114%), and exports to Taiwan increased 109,000 b/d (133%) in the first half of 2019 compared with the first half of 2018.
U.S. crude oil exports to Western Europe also increased 327,000 b/d (66%) during this time. First-half 2019 exports to the Netherlands increased 173,000 b/d (192%) and exports to the United Kingdom increased 74,000 b/d (53%) compared with first half 2018 (Figure 2).
As U.S. crude oil export volumes have increased, so have the number of export destinations. During first half of 2019, the number of U.S. crude oil export destinations surpassed the number of U.S. crude oil import sources. In 2009, the United States imported crude oil from an average of 35 sources each month. A decade later, in the first half of 2019, the average number of sources fell to 26. After the restrictions on exporting domestic crude oil were lifted at the end of 2015, the number of U.S. crude oil export destinations has increased to more than 30 as of the end of the first half of 2019 (Figure 3). Between January 2016 (the first full month of unrestricted U.S. crude oil exports) and June 2019, U.S. crude oil production has increased by 2.9 million b/d. During that same period, U.S. crude oil exports increased 2.7 million b/d, the equivalent of 98% of the absolute crude oil production increase.
Increasing U.S. crude oil production has both reduced crude oil imports and increased crude oil exports, but the reasons for changes in each are complex.
Fewer crude oil import sources is the result of increased U.S. production of light-sweet crude oils whereas most U.S. refineries are configured to process medium- to heavy- sour crude oils. The U.S. Energy Information Administration’s (EIA) report Technical Options for Processing Additional Light Tight Oil Volumes Within the United States, explains how U.S. refineries have accommodated much of the growth in U.S. crude oil production since 2010 with two limited- or no-investment-cost options: displacing imports of crude oil (primarily light crude oil, but also medium crude oil) from countries other than Canada and increasing refinery utilization rates. Displacing light crude oil imports has both reduced the volume of crude oil the United States imports and the number of sources.
The increase in the number of U.S. crude oil export destinations is the result of
National and international regulations increasingly limit the amount of sulfur present in transportation fuels. As global demand for heavy residual oils declines, many less complex refineries outside the United States, which can’t process and remove sulfur from heavy-sour crude oils, are processing more of the lighter and sweeter crude oils. To supply this increasing demand, U.S. port infrastructure along the U.S. Gulf Coast is expanding to accommodate increased crude oil tanker traffic and larger crude oil tankers loading for export. In addition, new and expanded pipelines are being built to transport crude oil from areas such as the Permian and Eagle Ford to the U.S. Gulf Coast.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell more than 1 cent from the previous week to $2.64 per gallon on September 30, 22 cents lower than the same time last year. The Midwest price fell by nearly 10 cents to $2.49 per gallon, the East Coast price fell by more than 3 cents to $2.51 per gallon, and the Gulf Coast price fell by nearly 3 cents to $2.33 per gallon. The West Coast price rose by 21 cents to $3.55 per gallon, and the Rock Mountain price increased by more than 1 cent to $2.71 per gallon.
The U.S. average diesel fuel price fell nearly 2 cents to $3.07 per gallon on September 30, 25 cents lower than a year ago. The Gulf Coast price fell by more than 3 cents to $2.83 per gallon, the East Coast price fell by nearly 2 cents to $3.07 per gallon, the West Coast and Midwest prices fell by nearly 1 cent, remaining at $3.65 per gallon and $2.99 per gallon, respectively, and the Rocky Mountain price fell less than 1 cent, remaining at $3.03 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.0 million barrels last week to 100.6 million barrels as of September 27, 2019, 13.0 million barrels (14.8%) greater than the five-year (2014-18) average inventory levels for this same time of year. Midwest, Gulf Coast, and East Coast inventories increased by 0.5 million barrels, 0.4 million barrels, and 0.2 million barrels, respectively. Rocky Mountain/West Coast inventories decreased by 0.1 million barrels. Propylene non-fuel-use inventories represented 4.3% of total propane/propylene inventories.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.
Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.
When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.
This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.
In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.
The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.
By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)
Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b
Headlines of the week
Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership: