In the August 2018 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts Brent crude oil prices to average $73 per barrel (b) in the second half of 2018 and decline to an average of $71/b in 2019 (Figure 1). Competing upside and downside price risks are expected to play a large role in price formation during the forecast period. Upside price risks stem largely from the possibility of supply outages when both petroleum inventories and spare crude oil production capacity for members of the Organization of the Petroleum Exporting Countries (OPEC) are lower than average. Downside price risks stem largely from potentially reduced demand because economic growth and resulting crude oil demand could be lower than forecast.
Daily and monthly average crude oil prices could vary significantly from annual average forecasts because global economic developments and geopolitical events in the coming months have the potential to push oil prices higher or lower than the current STEO price forecast.
EIA forecasts total global liquid fuels inventories to decrease by 0.3 million barrels per day (b/d) in 2018, followed by an increase of 0.3 million b/d in 2019 (Figure 2). Inventory changes of this magnitude should be considered mostly balanced, contributing to forecast Brent crude oil prices remaining between $70/b and $73/b from August 2018 through the end of 2019. However, the forecast for slight inventory increases in 2019 contributes to expectations of modest downward price pressure in 2019.
On the supply side, the combination of relatively low inventory and OPEC spare capacity levels elevates the risk of upward price movements if a supply disruption occurs or if forecast production growth does not materialize.
Changes in global petroleum inventories data are not collected directly, but are estimated based on forecasts for global production and consumption. However, inventory data for the United States and other countries within the Organization for Economic Cooperation and Development (OECD) are available and may provide insight into global supply. In terms of days of supply, OECD inventories are expected to remain less than the monthly average for the previous five years, so any outages could have a significant effect on crude oil prices (Figure 3).
In 2018 and in 2019, EIA expects OPEC spare crude oil production capacity to decrease from 2017 levels (Figure 4). Although spare capacity in 2016 was lower than that forecast for 2018 and 2019, OECD inventories were higher in 2016, as seen in Figure 3. OPEC spare production capacity is forecast to average 1.6 million b/d in 2018 and to fall to 1.3 million b/d in 2019, down from 2.1 million b/d in 2017 and lower than the 10-year (2008–17) average of 2.3 million b/d. With little spare capacity, risks on the supply side (including greater-than-forecast disruptions in Iran, Venezuela, or Libya) may have significant price impacts.
EIA forecasts OPEC’s petroleum and other liquids production to decrease from the 2017 level of 39.5 million b/d to 39.1 million b/d in 2018 and to 39.0 million b/d in 2019. The small decline in 2019 reflects crude oil production increases from some producers that nearly offset anticipated declines from other OPEC members.
Brent spot prices averaged more than $74/b in June 2018, up $10/b from December 2017. Price increases in 2018 have been largely driven by unplanned supply disruptions and the expected loss of some Iranian crude oil production by the end of the year because of renewed sanctions. The August 2018 STEO reflects the U.S. withdrawal from the Joint Comprehensive Plan of Action (JCPOA) and the plan to reinstate sanctions on companies doing business with Iran. Sanctions will likely affect the Iranian oil sector, which would limit the country’s crude oil production and exports by the end of 2018. Uncertainty remains regarding the degree to which the U.S. sanctions will take Iranian crude oil off the market.
Future crude oil production in Venezuela and Libya and the magnitude of the production response from other OPEC members and Russia are also highly uncertain. Developments regarding these and other variables could influence prices in either direction.
Concerns about the pace of future economic and oil consumption growth have likely contributed to demand side uncertainty. The August STEO forecasts global demand growth for petroleum and other liquids to average 1.66 million b/d in 2018 and 1.57 million b/d in 2019, down from the July STEO forecast of 1.72 million b/d and 1.71 million b/d for 2018 and 2019, respectively.
U.S. average regular gasoline price increases, diesel price decreases
The U.S. average regular gasoline retail price increased less than one cent from last week to remain at $2.85 per gallon on August 6, 2018, up 47 cents from the same time last year. Rocky Mountain and East Coast prices each rose over a penny to $2.92 per gallon and $2.80 per gallon, respectively, and Midwest prices increased less than one cent to $2.77 per gallon. West Coast and Gulf Coast prices each decreased less than one cent to $3.34 per gallon and $2.59 per gallon, respectively.
The U.S. average diesel fuel price decreased less than one cent from last week to $3.22 per gallon on August 6, 2018, 64 cents higher than year ago. Midwest prices fell nearly one cent to $3.15 per gallon, and West Coast, East Coast, and Gulf Coast prices each decreased less than a penny, remaining virtually unchanged at $3.72 per gallon, $3.22 per gallon, and $3.00 per gallon, respectively. Rocky Mountain prices were unchanged at $3.36 per gallon.
Propane/propylene inventories rise slightly
U.S. propane/propylene stocks increased by 0.1 million barrels last week to 66.4 million barrels as of August 3, 2018, 9.3 million barrels (12.2%) lower than the five-year (2013-2017) average inventory level for this same time of year. Gulf Coast inventories increased by 0.3 million barrels and Rocky Mountain/West Coast inventories rose slightly, remaining virtually unchanged. Midwest and East Coast inventories decreased by 0.2 million barrels and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 4.3% of total propane/propylene inventories.
For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.
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Less than two weeks ago, the VLCC Navarin arrived at Tanjung Pengerang, at the southern end of Peninsular Malaysia. It was carrying two million barrels of crude oil, split equally between Saudi Arab Medium and Iraqi Basra Light grades.
The RAPID refinery in Johor. An equal joint partnership between Malaysia’s Petronas and Saudi Aramco whose 300 kb/d mega refinery is nearing completion. Once questioned for its economic viability, RAPID is now scheduled to start up in early 2019, entering a market that is still booming and in demand of the higher quality, Euro IV and Euro V level fuels RAPID will produce.
Beyond fuel products, RAPID will also have massive petrochemical capacity. Meant to come on online at a later date, RAPID will have a collective capacity of some 7.7 million tons per annum of differentiated and specialty chemicals, including 3 mtpa of propylene. To be completed in stages, Petronas nonetheless projects that it will add some 3.3 million tons of petrochemicals to the Asia market by the end of next year. That’s blockbuster numbers, and it will elevate Petronas’ stature in downstream, bringing more international appeal to a refining network previously focused mainly on Malaysia. For its partner Saudi Aramco, RAPID is part of a multi-pronged strategy of investing mega refineries in key parts of the world, to diversify its business and ensure demand for its crude flows as it edges towards an IPO.
RAPID won’t be alone. Vietnam’s second refinery – the 200 kb/d Nghi Son – has finally started up this year after multiple delays. And in the same timeframe as RAPID, the Zhejiang refinery by Rongsheng Petro Chemical and the Dalian refinery by Hengli Petrochemical in China are both due to start up. At 400 kb/d each, that could add 1.1 mmb/d of new refining capacity in Asia within 1H19. And there’s more coming. Hengli’s Pulau Muara Besar project in Brunei is also aiming for a 2019 start, potentially adding another 175 kb/d of capacity. And just like RAPID, each of these new or recent projects has substantial petrochemical capacity planned.
That’s okay for now, since demand remains strong. But the danger is that this could all unravel. With American sanctions on Iran due to kick in November, even existing refineries are fleeing from contributing to Tehran in favour of other crude grades. The new refineries will be entering a tight market that could become even tighter. RAPID can rely on Saudi Arabia and Nghi Son can depend on Kuwait, both the Chinese projects are having to scramble to find alternate supplies for their designed diet of heavy sour crude. This race to find supplies has already sent Brent prices to four-year highs, and most in the industry are already predicting that crude oil prices will rise to US$100/b by the year’s end. At prices like this, demand destruction begins and the current massive growth – fuelled by cheap oil prices – could come to an end. The market can rapidly change again, and by the end of this decade, Asia could be swirling with far more oil products that it can handle.
Upcoming and recent Asia refineries:
Headline crude prices for the week beginning 8 October 2018 – Brent: US$84/b; WTI: US$74/b
Headlines of the week
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production
As domestic production continues to increase, the average density of crude oil produced in the United States continues to become lighter. The average API gravity—a measure of a crude oil’s density where higher numbers mean lower density—of U.S. crude oil increased in 2017 and through the first six months of 2018. Crude oil production with an API gravity greater than 40 degrees grew by 310,000 barrels per day (b/d) to more than 4.6 million b/d in 2017. This increase represents 53% of total Lower 48 production in 2017, an increase from 50% in 2015, the earliest year for which EIA has oil production data by API gravity.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, meaning lighter oils have higher API gravities. The increase in light crude oil production is the result of the growth in crude oil production from tight formations enabled by improvements in horizontal drilling and hydraulic fracturing.
Along with sulfur content, API gravity determines the type of processing needed to refine crude oil into fuel and other petroleum products, all of which factor into refineries’ profits. Overall U.S. refining capacity is geared toward a diverse range of crude oil inputs, so it can be uneconomic to run some refineries solely on light crude oil. Conversely, it is impossible to run some refineries on heavy crude oil without producing significant quantities of low-valued heavy products such as residual fuel.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production
API gravity can differ greatly by production area. For example, oil produced in Texas—the largest crude oil-producing state—has a relatively broad distribution of API gravities with most production ranging from 30 to 50 degrees API. However, crude oil with API gravity of 40 to 50 degrees accounted for the largest share of Texas production, at 55%, in 2017. This category was also the fastest growing, reaching 1.9 million b/d, driven by increasing production in the tight oil plays of the Permian and Eagle Ford.
Oil produced in North Dakota’s Bakken formation also tends to be less dense and lighter. About 90% of North Dakota’s 2017 crude oil production had an API gravity of 40 to 50 degrees. The oil coming from the Federal Gulf of Mexico (GOM) tends to be more dense and heavier. More than 34% of the crude oil produced in the GOM in 2017 had an API gravity of lower than 30 degrees and 65% had an API gravity of 30 to 40 degrees.
In contrast to the increasing production of light crude oil in the United States, imported crude oil continues to be heavier. In 2017, 7.6 million b/d (96%) of imported crude oil had an API gravity of 40 or below, compared with 4.2 million b/d (48%) of domestic production.
EIA collects API gravity production data by state in the monthly crude oil and natural gas production report as well as crude oil quality by company level imports to better inform analysis of refinery inputs and utilization, crude oil trade, and regional crude oil pricing. API gravity is also projected to continue changing: EIA’s Annual Energy Outlook 2018 Reference case projects that U.S. oil production from tight formations will continue to increase in the coming decades.