In the United Kingdom, electricity produced from coal declined from 42% of total electricity generation in 2012 to 7% in 2017. According to U.K. National Grid data, on April 21, 2017, the country went 24 hours without any electricity generated from coal for the first time since the 1880s. In January 2018, the U.K. government laid out an implementation plan to shut down all coal-fired electricity generation plants by 2025 that do not have carbon capture and storage technology.
Source: U.S. Energy Information Administration, based on Digest of U.K. Energy Statistics and National Statistics: Energy Trends
Note: 2017 values are estimates based on data through September.
Coal consumption has been declining in the United Kingdom for decades. Total coal consumption peaked at 244 million short tons (MMst) in 1956, the year the United Kingdom enacted the Clean Air Act. The Clean Air Act—prompted by the great London smog of 1952—prohibited the emission of dark smoke from industrial buildings, private homes, and railroad locomotives.
At the time, industrial coal use accounted for more than half of total U.K. coal consumption, and railroad and home use accounted for almost a quarter of total coal consumption. The remaining coal consumption in 1956—about 50 MMst—was mainly in the electric sector.
As industrial, railroad, and residential use of coal decreased, consumption of coal by the electric power sector increased, peaking at 99 MMst in 1980. Coal consumption in the electric power sector began a steep decline in 2013. Several factors contributed to the decline, including the implementation of the U.K. Carbon Price Floor (CPF), which increased the cost of carbon emissions for electric generators.
The United Kingdom’s CPF works in combination with the European Union’s Emissions Trading System (EU ETS). If the EU ETS carbon price is lower than the U.K. CPF, electric generators have to buy credits from the U.K. Treasury to make up the difference. The CPF applies to both generators that produce electricity for the grid and companies that produce electricity for their own use.
Source: U.S. Energy Information Administration, based on European Energy Exchange and House of Commons Library
The U.K. CPF is currently 18 British pounds sterling (GBP) per ton of carbon, the equivalent of about US $25 per metric ton, where it will remain at least through the 2019 fiscal year (which ends March 31, 2020). Since 2012, the EU ETS carbon price has stayed below 10 Euro per metric ton of carbon, the equivalent of about US $12.30 per metric ton. Although originally intended to increase annually, the CPF was capped from 2016 to 2020 to limit the impact on U.K. businesses. Discussions are ongoing about the value of the CPF after 2020.
For more information on the United Kingdom’s energy industry, see EIA’s recently updated United Kingdom Country Analysis Brief.
Principal contributor: Justine Barden
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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.