EIA expects Brent crude oil prices to average $73 per barrel in the second half of 2018, then fall to $69 per barrel in 2019
In the July 2018 update of its Short–Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that Brent crude oil prices will average $73 per barrel (b) in the second half of 2018 and $69/b in 2019. EIA expects West Texas Intermediate (WTI) crude oil prices will average $7/b lower than Brent prices in the second half of 2018 and $7/b lower in 2019 (Figure 1).
EIA’s forecast of global liquid fuels balances indicates a looser oil market in the second half of 2018 and through the end of 2019 compared with the tight oil market conditions that prevailed in 2017 and the first half of 2018. Although global petroleum and other liquid fuels inventories declined by an average of 0.5 million barrels per day (b/d) in 2017, EIA expects inventories to be relatively unchanged in 2018 and to increase by 0.6 million b/d in 2019 (Figure 2).
The forecast inventory builds in 2019 are mainly the result of expected liquid fuels production growth in the United States, Brazil, Canada, and Russia. EIA forecasts that these countries will collectively provide 2.2 million b/d out of the 2.4 million b/d of total global supply growth in 2019. Supply growth of this magnitude would outpace EIA’s forecast for global liquid fuels consumption growth of 1.7 million b/d for 2019.
EIA forecasts total U.S. crude oil production to average 10.8 million b/d in 2018, up 1.4 million b/d from 2017, and 11.8 million b/d in 2019. If realized, the forecast level for both years would surpass the previous U.S. record of 9.6 million b/d set in 1970. Crude oil production at these forecast levels would probably make the United States the world’s leading crude oil producer in both years.
Increased production from tight rock formations within the Permian region in Texas and New Mexico accounts for 0.6 million b/d of the expected 1.2 million b/d of crude oil production growth from June 2018 to December 2019. The remaining increase comes from the Bakken, Eagle Ford, other regions in the Lower 48 states, and the Federal Offshore Gulf of Mexico.
However, OECD inventory levels that have fallen below the five-year (2013–17) average and a forecast of low spare capacity among members of the Organization of the Petroleum Exporting Countries (OPEC) create conditions for possible price increases if additional supply disruptions occur or if forecast supply growth does not materialize (Figure 3). EIA expects OPEC surplus production capacity to average 1.7 million b/d in 2018 and to fall to 1.3 million b/d in 2019, a relatively low level compared with the 2008–17 average of 2.3 million b/d. Low OPEC crude oil surplus production capacity can be an indicator of tight oil market conditions. All of OPEC’s currently available surplus production capacity is in Saudi Arabia, Kuwait, the United Arab Emirates, and Qatar.
EIA forecasts OPEC crude oil production to average 31.9 million b/d in 2018, a decrease of 0.6 million b/d compared with the 2017 level. The forecast decline is mainly the result of Venezuela’s rapidly decreasing crude oil production, which fell to less than 1.4 million b/d as of June 2018, a 0.6 million b/d decrease compared with June 2017. OPEC output during the first half of 2018 was also lower as a result of the production caps placed on the group’s producers as agreed upon in the November 2016 OPEC production agreement that aimed to limit OPEC crude oil output to 32.5 million b/d.
OPEC crude oil production averaged 31.9 million b/d in June. Although the OPEC and non-OPEC participants agreed on November 30, 2017, to extend the production cuts through the end of 2018 to reduce global oil inventories, tightening market conditions led the group to relax the production cuts starting in July 2018. EIA expects that OPEC crude oil output will decrease by an average of less than 0.1 million b/d in 2019. This small decline reflects crude oil production increases from some producers that would mostly offset expected combined declines of more than 1.0 million b/d in Iran and Venezuela.
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price increased one cent from the previous week to $2.86 per gallon on July 9, up 56 cents from the same time last year. The Midwest and Gulf Coast prices each increased nearly two cents to $2.78 per gallon and $2.62 per gallon, respectively, the East Coast price increased one cent to $2.78 per gallon, and the West Coast price rose slightly, remaining virtually unchanged at $3.39 per gallon. The Rocky Mountain price decreased marginally, remaining virtually unchanged at $2.96 per gallon.
The U.S. average diesel fuel price increased less than a cent, remaining at $3.24 per gallon on July 9, up 76 cents from a year ago. The Rocky Mountain and East Coast prices each increased over a penny to $3.37 per gallon and $3.24 per gallon, respectively, the Midwest price rose nearly one cent to $3.18 per gallon, and the West Coast and Gulf Coast prices each rose slightly, remaining virtually unchanged at $3.75 per gallon and $3.00 per gallon, respectively.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 2.4 million barrels last week to 63.6 million barrels as of July 6, 2018, 6.4 million barrels (9.2%) lower than the five-year average inventory level for this same time of year. Gulf Coast and Midwest inventories each increased by 1.2 million barrels and Rocky Mountain/West Coast inventories increased by 0.2 million barrels, while East Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 3.7% of total propane/propylene inventories.
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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.