Source: U.S. Energy Information Administration, International Energy Statistics, International Atomic Energy Agency, Reuters, and Bloomberg
Nuclear electricity generation capacity in the Middle East is expected to increase from 3.6 gigawatts (GW) in 2018 to 14.1 GW by 2028 because of new construction starts and recent agreements between Middle East countries and nuclear vendors. The United Arab Emirates (UAE) will lead near-term growth by installing 5.4 GW of nuclear capacity by 2020.
The growth in nuclear capacity in the Middle East is largely attributable to countries in the region seeking to enhance energy security by reducing reliance on fossil fuel resources. Fossil fuels accounted for 97% of electricity production in the Middle East in 2017, with natural gas accounting for about 66% of electricity generation and oil for 31%. The remaining 3% of electricity generation in Middle East countries comes from nuclear, hydroelectricity, and other renewables.
Middle East countries are also adopting nuclear generation to meet increasing electricity demand resulting from population and economic growth. Regional electricity production was more than 1,000 billion kilowatthours (kWh) in 2017, and EIA expects electricity demand to increase 30% by 2028, based on projections in the latest International Energy Outlook. This growth rate is higher than the average global growth rate of 18% over that same period, and higher than the 24% expected growth in non-OECD (Organization for Economic Cooperation and Development) countries.
Developments in building nuclear capacity in the region include
Iran is building a two-unit nuclear plant, Bushehr-II, which is designed to add 1.8 GW of nuclear capacity when completed in about 2026. Iran’s original Bushehr-I facility, which came online in 2011, was the first nuclear power plant in the Middle East. Bushehr-I has one 1.0 GW reactor unit producing about 5.9 million kWh of electricity per year.
The UAE is currently constructing the four-unit Barakah nuclear power plant, which is expected to be completed by the end of 2020. The 1.3 GW Barakah unit 1, which was started in 2012 and completed in 2017, is expected to begin electricity production by mid-2018.
Turkey began construction of the Akkuyu nuclear power plant in late 2017. Akkuyu is a four-unit facility designed to add 4.8 GW of nuclear capacity to Turkey’s generation mix. The first reactor unit is scheduled to be completed by 2025.
Saudi Arabia is planning to build its first nuclear power plant and is expected to award a construction contract for a 2.8 GW facility by the end of 2018. It has solicited bids from five vendors from the United States, South Korea, France, Russia, and China to carry out the engineering, procurement, and construction work on two nuclear reactors. Construction is expected to begin in about 2021 at one of the two proposed sites—either Umm Huwayd or Khor Duweihin.
Jordan plans to install a two-unit 2.0 GW nuclear plant and has been conducting nuclear feasibility studies with Russia’s Rosatom since 2016. In early 2017, Jordan solicited bids for supplying turbines and electrical systems, and construction is expected to begin in 2019 and to be completed by 2024.
Source: U.S. Energy Information Administration, International Energy Outlook 2017, International Atomic Energy Agency, World Nuclear Association
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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.