World chokepoints for maritime transit of oil are a critical part of global energy security. About 61% of the world's petroleum and other liquids production moved on maritime routes in 2015. The Strait of Hormuz and the Strait of Malacca are the world's most important strategic chokepoints by volume of oil transit.
The U.S. Energy Information Administration (EIA) defines world oil chokepoints as narrow channels along widely used global sea routes, some so narrow that restrictions are placed on the size of the vessel that can navigate through them. Chokepoints are a critical part of global energy security because of the high volume of petroleum and other liquids transported through their narrow straits.
In 2015, total world petroleum and other liquids supply was about 96.7 million barrels per day (b/d).1 EIA estimates that about 61% that amount (58.9 million b/d) traveled via seaborne trade.2 Oil tankers accounted for almost 28% of the world’s shipping by deadweight tonnage in 2016, according to data from the United Nations Conference on Trade and Development (UNCTAD), having fallen steadily from 50% in 1980.3
International energy markets depend on reliable transport routes. Blocking a chokepoint, even temporarily, can lead to substantial increases in total energy costs and world energy prices. Chokepoints also leave oil tankers vulnerable to theft from pirates, terrorist attacks, political unrest in the form of wars or hostilities, and shipping accidents that can lead to disastrous oil spills.
The seven chokepoints highlighted in this report are part of major trade routes for global seaborne oil transportation. Disruptions to these routes could affect oil prices and add thousands of miles of transit in alternative routes. By volume of oil transit, the Strait of Hormuz, leading out of the Persian Gulf, and the Strait of Malacca (linking the Indian and Pacific Oceans) are the world's most important strategic chokepoints. This report also discusses the role of the Cape of Good Hope, which is not a chokepoint but is a major trade route and potential alternate route to certain chokepoints.
Figure 1. Daily transit volumes through world maritime oil chokepoints
All estimates in million barrels per day. Includes crude oil and petroleum liquids. Based on 2016 data.
Source: U.S. Energy Information Administration
Table 1. Volume of crude oil and petroleum products transported through world chokepoints and the Cape of Good Hope, 2011-16 (million b/d)Location201120122013201420152016Strait of Hormuz17.016.816.616.917.018.5Strait of Malacca14.515.115.415.515.516.0Suez Canal and SUMED Pipeline22.214.171.124.25.45.5Bab el-Mandab126.96.36.199.34.74.8Danish Straits3.03.33.13.03.23.2Turkish Straits188.8.131.52.62.42.4Panama Canal0.80.80.80.91.00.9Cape of Good Hope184.108.40.206.95.15.8World maritime oil trade55.556.456.556.458.9n/aWorld total petroleum and other liquids supply88.890.891.393.896.797.2Note: Data for Panama Canal are by fiscal year.
Sources: U.S. Energy Information Administration analysis based on Lloyd's List Intelligence, Panama Canal Authority, Argus FSU, Suez Canal Authority, GTT, BP Statistical Review of World Energy, IHS Waterborne, Oil and Gas Journal, and UNCTAD, using EIA conversion factors.4
Ships carrying crude oil and petroleum products are limited by size restrictions imposed by maritime oil chokepoints. The global crude oil and refined product tanker fleet uses a classification system to standardize contract terms, to establish shipping costs, and to classify vessels for chartering contracts. This system, known as the Average Freight Rate Assessment (AFRA) system, was established by Royal Dutch Shell six decades ago, and the London Tanker Brokers' Panel (LTBP), an independent group of shipping brokers, oversees the system.
AFRA uses a scale that classifies tanker vessels according to deadweight tons—a measure of a ship's capacity to carry cargo. The approximate capacity of a ship in barrels is determined using an estimated 90% of a ship's deadweight tonnage, which is multiplied by a barrel-per-metric-ton conversion factor specific to each type of petroleum product and crude oil, as liquid fuel densities vary by type and grade.
The smaller vessels on the AFRA scale—the General Purpose (GP) and Medium Range (MR) tankers—are commonly used to transport cargos of refined petroleum products over relatively shorter distances, such as from Europe to the U.S. East Coast. Their smaller size allows them to access most ports around the globe. A GP tanker can carry between 70,000 barrels and 190,000 barrels of motor gasoline (3.2-8 million gallons), and an MR tanker can carry between 190,000 barrels and 345,000 barrels of motor gasoline (8-14.5 million gallons).
Long Range (LR) class ships are the most common ships in the global tanker fleet, as they are used to carry both refined products and crude oil. These ships can access most large ports that ship crude oil and petroleum products. An LR1 tanker can carry between 345,000 barrels and 615,000 barrels of gasoline (14.5-25.8 million gallons) or between 310,000 barrels and 550,000 barrels of light sweet crude oil.
A large portion of the global tanker fleet is classified as AFRAMAX. AFRAMAX vessels are ships between 80,000 deadweight tons and 120,000 deadweight tons. This ship size is popular with oil companies for logistical purposes, and many ships have been built within these specifications. Because the AFRAMAX range exists somewhere between the LR1 and LR2 AFRA scales, the LTBP does not publish a freight assessment specifically for AFRAMAX vessels.
Over the history of AFRA, vessels grew in size, and newer classifications were added. The Very Large Crude Carrier (VLCC) and Ultra-Large Crude Carrier (ULCC) were added as the global oil trade expanded and larger vessels provided better economics for crude oil shipments. VLCCs are responsible for most crude oil shipments around the globe, including in the North Sea, home of the crude oil price benchmark Brent. A VLCC can carry between 1.9 million and 2.2 million barrels of a West Texas Intermediate (WTI) type crude oil.
Figure 2. Average Freight Rate Assessment (AFRA) Scale-Fixed
Source: U.S. Energy Information Administration, London Tanker Brokers' Panel5
Note: AFRAMAX is not an official vessel classification on the AFRA scale but is shown here for comparison.
The Strait of Hormuz is the world's most important chokepoint, with an oil flow of 17 million b/d in 2015, about 30% of all seaborne-traded crude oil and other liquids during the year. In 2016, total flows through the Strait of Hormuz increased to a record high of 18.5 million b/d.
Located between Oman and Iran, the Strait of Hormuz connects the Persian Gulf with the Gulf of Oman and the Arabian Sea. The Strait of Hormuz is the world's most important oil chokepoint because its daily oil flow of about 17 million barrels per day in 2015, accounted for 30% of all seaborne-traded crude oil and other liquids. The volume that traveled through this vital choke point increased to 18.5 million b/d in 2016.
EIA estimates that about 80% of the crude oil that moved through this chokepoint went to Asian markets, based on data from Lloyd’s List Intelligence tanker tracking service.6China, Japan, India, South Korea, and Singapore are the largest destinations for oil moving through the Strait of Hormuz.
Qatar exported about 3.7 trillion cubic feet per year of liquefied natural gas (LNG) through the Strait of Hormuz in 2016, according to BP’s Statistical Review of World Energy 2017.7 This volume accounts for more than 30% of global LNG trade. Kuwait imports LNG volumes that travel northward through the Strait of Hormuz.
At its narrowest point, the Strait of Hormuz is 21 miles wide, but the width of the shipping lane in either direction is only two miles wide, separated by a two-mile buffer zone. The Strait of Hormuz is deep enough and wide enough to handle the world's largest crude oil tankers, with about two-thirds of oil shipments carried by tankers in excess of 150,000 deadweight tons coming through this Strait.
Most potential options to bypass Hormuz are currently not operational. Only Saudi Arabia and the United Arab Emirates (UAE) have pipelines that can ship crude oil outside of the Persian Gulf and have additional pipeline capacity to circumvent the Strait of Hormuz. At the end of 2016, the total available crude oil throughput pipeline capacity from the two countries combined was estimated at 6.6 million b/d, while the two countries combined had roughly 3.9 million b/d of unused bypass capacity (Table 2).
Saudi Arabia has the 746-mile Petroline, also known as the East-West Pipeline, which runs across Saudi Arabia from its Abqaiq complex to the Red Sea. The Petroline system consists of two pipelines with a total nameplate (installed) capacity of about 4.8 million b/d. The 56-inch pipeline has a nameplate capacity of 3 million b/d. The 48-inch pipeline had been previously operating as a natural gas pipeline, but Saudi Arabia converted it to an oil pipeline. The switch increased Saudi Arabia's spare oil pipeline capacity to bypass the Strait of Hormuz from 1 million b/d to 2.8 million b/d, but this volume is only achievable if the system operates at its full nameplate capacity. In 2016, Saudi Aramco announced that it plans to expand the capacity of the East-West pipeline to 7 million b/d, with a scheduled completion by end-2018. To date, there has been little progress on the pipeline expansion.
Saudi Arabia also operates the Abqaiq-Yanbu natural gas liquids pipeline, which has a capacity of 290,000 b/d.
The UAE operates the Abu Dhabi Crude Oil Pipeline (1.5 million b/d) that runs from Habshan (a collection point for Abu Dhabi's onshore oil fields) to the port of Fujairah on the Gulf of Oman, which allows crude oil shipments to circumvent the Strait of Hormuz. The government plans to increase the capacity of this pipeline to 1.8 million b/d.
Figure 3. Map of the Strait of Hormuz
Source: U.S. Department of State
Saudi Arabia has two additional pipelines that run parallel to the Petroline system and bypass the Strait of Hormuz, but neither of the pipelines has the ability to transport additional volumes of oil if the Strait of Hormuz is closed.
The 1.65 million b/d, 48-inch Iraqi Pipeline in Saudi Arabia (IPSA), which runs parallel to the Petroline from pump station #3 (11 pumping stations run along the Petroline) to the port of Mu'ajjiz, just south of Yanbu, Saudi Arabia, was built in 1989 to carry 1.65 million b/d of crude oil from Iraq to the Red Sea. The pipeline closed indefinitely following the August 1990 Iraqi invasion of Kuwait. In June 2001, Saudi Arabia seized ownership of IPSA as compensation for debts Iraq owed and converted it to transport natural gas to power plants.
Other pipelines, such as the Trans-Arabian Pipeline (TAPLINE) running from Qaisumah in Saudi Arabia to Sidon in Lebanon or a strategic oil pipeline between Iraq and Turkey, have been out of service for years because of war damage, disuse, or political disagreements. These pipelines would require extensive renovation before they could transport oil. Relatively small quantities, several hundred thousand barrels per day at most, could also be transported by truck if the Strait of Hormuz were closed.
Table 2. Operating pipelines that bypass the Strait of Hormuz, 2016Pipeline nameCountryStatusCapacityThroughputUnused capacityPetroline (East-West Pipeline)Saudi ArabiaOperating220.127.116.11Abu Dhabi Crude Oil PipelineUnited Arab EmiratesOperating18.104.22.168Abqaiq-Yanbu Natural Gas Liquids PipelineSaudi ArabiaOperating0.30.30.0Iraqi Pipeline in Saudi Arabia (IPSA)Saudi ArabiaConverted to natural gas0.0-0.0Total 22.214.171.124Note: All estimates expressed in million barrels per day (b/d). Unused capacity is defined as pipeline capacity that is not currently used but can be readily available.
Sources: U.S. Energy Information Administration, Lloyd’s List Intelligence.
The Strait of Malacca, linking the Indian Ocean and the Pacific Ocean, is the shortest sea route between the Middle East and growing Asian markets. Flows through the Strait of Malacca rose to 16 million b/d in 2016, retaining its position as the second busiest transit chokepoint.
The Strait of Malacca, located between Indonesia, Malaysia, and Singapore, links the Indian Ocean to the South China Sea and to the Pacific Ocean. The Strait of Malacca is the shortest sea route between Persian Gulf suppliers and the Asian markets—notably China, Japan, South Korea, and the Pacific Rim.
Oil shipments through the Strait of Malacca supply China and Indonesia, two of the world's fastest-growing economies. This Strait is the primary chokepoint in Asia, with an estimated 16.0 million b/d flow in 2016, compared with 14.5 million b/d in 2011. Crude oil generally makes up between 85% and 90% of total oil flows per year, and petroleum products account for the remainder (Table 3).
At its narrowest point in the Phillips Channel of the Singapore Strait, the Strait of Malacca is only about 1.7 miles wide, creating a natural bottleneck with the potential for collisions, grounding, or oil spills.8 According to the International Maritime Bureau's Piracy Reporting Centre, piracy, including attempted theft and hijackings, is a threat to tankers in the Strait of Malacca, and ships saw an increasing number of attacks in 2015. Data for 2016 were not available at the time of publication.9
If the Strait of Malacca were blocked, nearly half of the world's fleet would be required to reroute around the Indonesian archipelago, such as through the Lombok Strait between the Indonesian islands of Bali and Lombok, or through the Sunda Strait between Java and Sumatra.10 Rerouting would tie up global shipping capacity, add to shipping costs, and potentially affect energy prices.
Several proposals have been made to build bypass options and reduce tanker traffic through the Strait of Malacca. In particular, China and Myanmar (Burma) commissioned the Myanmar-China natural gas pipeline in 2013 that stretches from Myanmar's ports in the Bay of Bengal to the Yunnan province of China. The pipeline has a capacity of 424 billion cubic feet per year. The oil portion of the pipeline was completed in August 2014 and it is now operational at full capacity since the 260,000 b/d refinery in Yunnan, China, began operating in June 2017. The Myanmar-China oil line transports Middle Eastern oil, allowing it to bypass the Strait of Malacca.11
The Strait of Malacca is also an important transit route for liquefied natural gas (LNG) from Persian Gulf and African suppliers, particularly Qatar, to East Asian countries with growing LNG demand. The biggest importers of LNG in the region are Japan and South Korea.
Table 3. Strait of Malacca oil and liquefied natural gas (LNG) flows, 2011-16million barrels per day201120122013201420152016Total oil flows through Strait of Malacca14.515.115.415.515.516.0crude oil12.813.213.313.313.914.6refined products126.96.36.199.21.61.4LNG (Tcf per year)188.8.131.52.13.63.2Notes: Tcf = Trillion cubic feet.
Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, IHS Waterborne, BP.12
Figure 4. Map of the Strait of Malacca
Source: CIA Factbook
The Suez Canal and the SUMED Pipeline are strategic routes for Persian Gulf oil and natural gas shipments to Europe and North America. These two routes combined accounted for about 9% of the world’s seaborne oil trade in 2015.
The Suez Canal is located in Egypt and connects the Red Sea and the Gulf of Suez with the Mediterranean Sea. In 2016, total petroleum and other liquids (crude oil and refined products) and LNG accounted for 17% and 6% of total Suez cargoes, measured by net metric tonnage, respectively. The Suez Canal cannot handle Ultra Large Crude Carriers (ULCC) and fully laden Very Large Crude Carriers (VLCC) class crude oil tankers. The Suezmax was the largest ship that could navigate through the canal until 2010, when the Suez Canal Authority extended the canal depth to 66 feet to allow more than 60% of all tankers to transit the Canal, according to the Suez Canal Authority. In addition, almost 93% of bulk carriers and 100% of container ships have been able to transit the Suez Canal since 2010.13
In 2016, 3.9 million b/d of total oil (crude oil and refined products) transited the Suez Canal in both directions, according to data published by the Suez Canal Authority. Northbound flows rose by about 300,000 b/d in 2016, but southbound shipments decreased for the first time since at least 2009. Increased crude oil exports from Iraq and Saudi Arabia to Europe contributed to higher northbound traffic, while lower exports of petroleum products from Russia to Asia contributed the most to lower southbound traffic.
Most oil transiting the Suez Canal was sent northbound (2.4 million b/d) toward European and North American markets, and the remainder was sent southbound (1.5 million b/d), mainly toward Asian markets. Oil exports from Persian Gulf countries (Saudi Arabia, Iraq, Kuwait, United Arab Emirates, Iran, Oman, Qatar, and Bahrain) accounted for 84% of Suez Canal northbound oil flows. The largest importers of northbound oil flows through the Suez Canal in 2016 were European countries (78%) and the United States (14%). Oil exports from Russia accounted for the largest share of (17%) of Suez southbound oil flows, followed by Turkey (15%) and Netherlands (11%). North Africa (Algeria and Libya) made up 12% of the southbound flow. The largest importers of Suez southbound oil flows were Asian countries, with Singapore, China and India accounting for more than 50% of the total.
Total traffic through the Suez Canal has been steadily increasing since 2009, and total oil flows rose to more than 2 million b/d by 2014. The increase in oil shipments during 2015 and 2016 in particular reflect increased OPEC production and exports, including increased output in Iraq and Saudi Arabia, and increased exports from Iran in 2016 as sanctions targeting its oil exports were eased.
The 200-mile long SUMED Pipeline, or Suez-Mediterranean Pipeline, transports crude oil through Egypt from the Red Sea to the Mediterranean Sea. The crude oil flows through two parallel pipelines that are 42 inches in diameter, which have a total pipeline capacity of 2.34 million b/d. Oil flows north starting at the Ain Sukhna terminal along the Red Sea coast to its end point at the Sidi Kerir terminal on the Mediterranean Sea. SUMED is owned by the Arab Petroleum Pipeline Company, a joint venture between the Egyptian General Petroleum Corporation (50%), Saudi Aramco (15%), Abu Dhabi's International Petroleum Investment Company (15%), multiple Kuwaiti companies (15%), and Qatar Petroleum (5%). 14
The SUMED Pipeline is the only alternate route to transport crude oil from the Red Sea to the Mediterranean Sea if ships cannot navigate through the Suez Canal. Closure of the Suez Canal and the SUMED Pipeline would require oil tankers to divert around the southern tip of Africa, the Cape of Good Hope, which would add approximately 2,700 miles to the transit from Saudi Arabia to the United States. The increased transit time would also increase costs and shipping time, according to the U.S. Department of Transportation.15 According to the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8–10 days to the United States. 16
Fully laden VLCCs going toward the Suez Canal also use the SUMED Pipeline for lightering. Lightering occurs when a vessel needs to reduce its weight and draft by offloading cargo to enter a restrictive waterway, such as a canal. The Suez Canal is not deep enough for a fully-laden VLCC and, therefore, a portion of the crude is offloaded at the SUMED Pipeline at the Ain Sukhna terminal. The now partially-laden VLCC goes through the Suez Canal and picks up the offloaded crude at the other end of the pipeline at the Sidi Kerir terminal.
In 2016, 1.6 million b/d of crude oil was transported through the SUMED Pipeline to the Mediterranean Sea, and then loaded onto tankers for seaborne trade. Flows via SUMED were relatively unchanged compared with 2015. Total oil flows via SUMED and the Suez Canal were 5.5 million b/d in 2016, 100,000 b/d more than in 2015. Total oil flows via the Suez Canal and SUMED pipeline accounted for about 9% of total seaborne-traded oil in 2015.
Table 4. Suez Canal and SUMED pipeline flows of oil and liquefied natural gas (LNG), 2011-16million barrels per day201120122013201420152016Total oil flows via the Suez Canal and SUMED pipeline184.108.40.206.25.45.5Suez Canal total flowscrude oil0.71.41.51.81.61.8refined products220.127.116.11.02.22.0total oil18.104.22.168.73.83.9LNG (Tcf per year)22.214.171.124.21.31.2Suez northbound flowscrude oil0.50.91.11.41.21.4refined products0.90.80.70.80.81.0total oil126.96.36.199.12.12.4LNG (Tcf per year)188.8.131.52.10.8Suez southbound flowscrude oil0.20.50.40.40.40.4refined products0.60.8184.108.40.206total oil0.81.31.31.61.71.5LNG (Tcf per year)0.20.30.20.30.30.3SUMED pipeline crude oil flows220.127.116.11.51.61.6Notes: Totals may not exactly match corresponding values as a result of independent rounding. Tcf = Trillion cubic feet.
Source: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Suez Canal Authority (with EIA conversions).
LNG flows through the Suez Canal in both directions were 1.2 Tcf in 2016, accounting for 9% of total LNG transported worldwide.
LNG flows through the Suez Canal in both directions were 1.2 trillion cubic feet (Tcf) in 2016, accounting for about 9% of total LNG traded worldwide. Southbound LNG transit mostly originates in Nigeria, France (as re-exports), and Trinidad and Tobago, mostly destined for Egypt, Jordan, and Japan, which combined account for more than 65% of the total southbound LNG imports through the canal. Nearly all of the northbound transit (99%) is from Qatar and is mainly destined for European markets. The rapid growth in LNG flows through the Suez Canal after 2008 represents the expansion of LNG exports from Qatar.
LNG flows through the Suez Canal in both directions have declined from their peak of almost 2.1 Tcf in 2011. The decrease mostly reflects the fall in northbound LNG flows and is consistent with LNG import data for the United States, which show that total LNG imports fell dramatically between 2011 and 2016. U.S. LNG imports from Qatar fell from 91 billion cubic feet in 2011 to zero in 2014 and have remained at this level since then. The changes reflect growing domestic natural gas production in the United States, a decrease in LNG demand in some European countries, and strong competition for LNG in the global market. As a result, Suez LNG flows as a share of total LNG traded worldwide fell to 9% in 2016, compared with 18% in 2011.
Figure 5. Map of Suez Canal/SUMED pipeline
Source: U.S. Energy Information Administration, IHS EDIN.
Closing the Bab el-Mandeb Strait could keep tankers in the Persian Gulf from reaching the Suez Canal and the SUMED Pipeline, diverting them around the southern tip of Africa.
The Bab el-Mandeb Strait is a chokepoint between the Horn of Africa and the Middle East, and it is a strategic link between the Mediterranean Sea and the Indian Ocean. The strait is located between Yemen, Djibouti, and Eritrea, and it connects the Red Sea with the Gulf of Aden and the Arabian Sea. Most exports from the Persian Gulf that transit the Suez Canal and the SUMED Pipeline also pass through Bab el-Mandeb. An estimated 4.8 million b/d of crude oil and refined petroleum products flowed through this waterway in 2016 toward Europe, the United States, and Asia, an increase from 3.3 million b/d in 2011.
The Bab el-Mandeb Strait is 18 miles wide at its narrowest point, limiting tanker traffic to two 2-mile-wide channels for inbound and outbound shipments. Closure of the Bab el-Mandeb could keep tankers originating in the Persian Gulf from reaching the Suez Canal or the SUMED Pipeline, diverting them around the southern tip of Africa, which would add to transit time and cost. In addition, European and North African southbound oil flows could no longer take the most direct route to Asian markets via the Suez Canal and Bab el-Mandeb.
Table 5. Bab el-Mandeb oil flows, 2011-16million b/d201120122013201420152016Total oil flows18.104.22.168.34.74.8Northbound2.02.02.12.22.52.8Southbounds22.214.171.124.12.22.0Note: Totals may not exactly match corresponding values as a result of independent rounding.
Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Suez Canal Authority, and GTT, using EIA conversion factors.
Figure 6. Map of Bab el-Mandeb
Source: CIA Factbook
Although still an important chokepoint for petroleum liquids transit from the Caspian Sea region, the Turkish Straits have seen declining transit volumes since 2011, falling to 2.4 million b/d in 2016. Oil moving through these straits supplies Western and Southern Europe.
The Turkish Straits, which includes the Bosporus and Dardanelles waterways, divide Asia from Europe. The Bosporus is a 17-mile waterway that connects the Black Sea with the Sea of Marmara. The Dardanelles is a 40-mile waterway that links the Sea of Marmara with the Aegean and Mediterranean Seas.17 Both waterways are located in Turkey and supply Western and Southern Europe with oil from Russia and the Caspian Sea region.
An estimated 2.4 million b/d of crude oil and petroleum products flowed through the Turkish Straits in 2016. More than 80% of this volume was crude oil. These Black Sea ports are among the primary oil export routes for Russia and other Eurasian countries including Azerbaijan and Kazakhstan.
Oil shipments through the Turkish Straits decreased from 2.9 million b/d in 2011 to 2.4 million b/d in 2016. At its peak, more than 3.4 million b/d transited the straits in 2004, but the volume that traveled through the Turkish Straits fell in the mid-2000s as Russia shifted crude oil exports away from the Black Sea and toward the Baltic ports. Subsequent increases in production and exports from Azerbaijan and Kazakhstan resulted in an increase in shipments through the Turkish Straits, but the increasing trend did not last: Turkish Straits have seen a steady decrease in traffic over the past five years. These volumes may increase in the future as Kazakhstan’s production of crude oil increases and the country exports more crude oil via Black Sea. EIA expects Kazakhstan’s crude oil production to increase through at least the end of 2018 as volumes from the country’s Kashagan field continue to rise.
Only half a mile wide at the narrowest point, the Turkish Straits are among the world’s most difficult waterways to navigate because of their sinuous geography. About 48,000 vessels transit the straits each year, making this area one of the world’s busiest maritime chokepoints.18 Commercial shipping has the right of free passage through the Turkish Straits in peacetime, although Turkey claims the right to impose regulations for safety and environmental purposes. Bottlenecks and heavy traffic also create problems for oil tankers in the Turkish Straits.
Figure 7. Map of Turkish Straits
Source: U.S. Government
The Panama Canal is not a significant route for U.S. petroleum trade. The recently completed expansion of the canal is unlikely to significantly change crude oil and petroleum product flows, with the exception of U.S. propane exports. Crude oil and petroleum liquids tankers accounted for a small portion of total transit traffic through the canal in 2016.
The Panama Canal is an important route connecting the Pacific Ocean with the Caribbean Sea and the Atlantic Ocean. The canal is 50 miles long and only 110 feet wide at its narrowest point—the Culebra Cut—at the Continental Divide.19 More than 13,000 vessels transited the Panama Canal in fiscal year 2016, representing roughly 204 million tons of cargo.20 Goods originating in or traveling to the United States accounted for more than 67% of the total shipments passing through the Panama Canal during 2016; China’s share was a distant second at roughly 19%.21
Alternatives to the Panama Canal include the Straits of Magellan, Cape Horn, and Drake Passage at the southern tip of South America, but these routes would significantly increase transit times and costs, adding about 8,000 miles of travel.
Although petroleum and petroleum products represented 27% of the principal commodities that crossed through the Panama Canal from the Atlantic to the Pacific in 2016, that canal is not a significant route for global petroleum and petroleum product transit. Northbound (Pacific to Atlantic) traffic of petroleum and petroleum products accounted for only 9% of the total products traveling through the canal.22 In 2015, 1.7% of total global maritime petroleum and petroleum product flows went through the Panama Canal. According to the Panama Canal Authority, 921,000 b/d of petroleum and petroleum products were transported through the canal in fiscal year 2016, of which 843,000 b/d were refined products and the remainder was crude oil.23 About 84% of total petroleum (775,000 b/d) went southbound from the Atlantic to the Pacific in 2016.24
Some oil tankers, such as the ULCC (Ultra Large Crude Carrier) class tankers, can be nearly five times larger than the maximum capacity of the canal. To make the canal more accessible, the Panama Canal Authority, the body that operates the Canal, undertook an expansion program that was completed in June 2016. With the expansion, the Panama Canal Authority inaugurated a third set of locks that allows larger ships to transit the canal. This expansion was the first one since the canal was completed in 1914.25
The canal expansion involved deepening and widening some portions of the canal and constructing an additional, larger set of locks. Unlike the old lock system, which had two lanes of side-by-side traffic, the new set of locks is one large lane and allows four transits per day, supplementing the 25 daily transits using the older lock system. The wider and deeper navigation channels and larger locks allow for the transit of larger vessels through the canal. The maximum vessel dimensions in the old lock system, known as Panamax vessels, limited tankers to those of approximately 300,000 to 500,000 barrels of capacity of petroleum products such as gasoline and diesel fuel. The newer lock system allow the larger Neopanamax vessels to transit the canal, with estimated petroleum product capacities of 400,000 to 600,000 barrels (Figure 8).
The expansion of the Panama Canal is not likely to affect crude oil and petroleum product flows in the future, with the exception of U.S. propane exports. Previously, the size limitations of the canal created logistical bottlenecks for U.S. propane exports travelling to markets in Asia, necessitating ship-to-ship transfers. The new, larger Panama Canal locks allow most Very Large Gas Carriers (VLGC), the type of ship that carries propane and other hydrocarbon gas liquids (HGL), to transit.
Figure 8. Panama Canal and Lock System
Source: U.S. Energy Information Administration
Figure 9. Panama Canal size restrictions
Figure 10. Map of Panama Canal
Source: CIA World Factbook
Table 6. Panama Canal and oil flows, 2011-16thousand barrels per day201120122013201420152016Panama Canal total flowstotal oil7688138638771031934crude oil1211209213313479refined products647693771744897855Panama Canal southbound flowstotal oil609696719701826785crude oil697240486047refined products541624679653766738Panama canal northbound flowstotal oil158117144176205149crude oil524852847432refined products106699291131116Notes: Totals may not equal the sum of the components due to independent rounding. Data for the Panama Canal are by fiscal years (October 1 to September 30).
Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Panama Canal Authority (with EIA conversions).26
The Trans-Panama Pipeline (TPP), operated by Petroterminal de Panama, S.A. (PTP), is located outside the former Canal Zone near the Costa Rican border. It runs from the port of Charco Azul on the Pacific coast to the port of Chiriqui Grande in Bocas del Toro, Panama, on the Caribbean Sea. The pipeline began operating in 1982 with the original purpose of facilitating crude oil shipments from Alaska's North Slope to refineries in the Caribbean and in the U.S. Gulf Coast.27 However, in 1996, the TPP was shut down as oil companies began shipping Alaskan crude oil along alternate routes. In August 2010, the flow of the TPP was reversed, and the pipeline now transports oil from the Caribbean to the Pacific.28
In 2012, BP and PTP signed a seven-year transportation and storage agreement allowing BP to lease storage facilities located on the Caribbean and Pacific coasts of Panama and to use the pipeline to transport crude oil to U.S. West Coast refiners. According to PTP, BP has leased 5.4 million barrels of PTP's storage and committed to east-to-west shipments through the pipeline averaging 100,000 b/d. The route reduces the transport time and the costs of ships that have to travel around Cape Horn at the southern tip of South America to get to the U.S. West Coast.29 Shell, also reportedly signed a three-year agreement to lease capacity in early 2017, gaining access to storage and transshipment facilities, the pipeline network, and tanker docks for oil loading.30 According to Lloyd’s List Intelligence, 111,000 b/d of crude oil was transported through the pipeline to the port of Charco Azul in 2016.
The Danish Straits are a vital route for Russian seaborne oil exports to Europe.
The Danish Straits are a series of channels that connect the Baltic Sea to the North Sea. They are an important route for Russian seaborne oil exports to Europe. An estimated 3.2 million b/d of crude oil and petroleum products flowed through the Danish Straits in 2016.
Russia shifted a significant portion of its crude oil exports to its Baltic ports after opening the port of Primorsk in 2005. In 2011, Primorsk oil exports accounted for almost half of all exports through the Danish Straits, although the volume fell to 32% in 2016. A small amount of oil (less than 50,000 b/d), primarily from Norway and the United Kingdom, also flowed eastward to Scandinavian markets in 2016.
Figure 11. Map of Danish Straits
Source: CIA Factbook
Although not a chokepoint, the Cape of Good Hope is a major global trade route. Crude oil flows around the Cape accounted for about 9% of all seaborne-traded oil.
The Cape of Good Hope, located on the southern tip of South Africa, is a significant transit point for oil tanker shipments around the globe. EIA estimates about 5.8 million b/d of seaborne-traded crude oil moved around the Cape of Good Hope in both directions in 2016. In 2015, crude oil transit around the Cape accounted for roughly 9% of global maritime trade of 5.1 million b/d.
In 2016, 4.3 million b/d of crude oil around the world moved eastbound, originating mostly from Africa (2.2 million b/d) and from South America and the Caribbean (1.6 million b/d). Eastbound crude oil flows were nearly all destined for Asian markets (4.1 million b/d). In the opposite direction, nearly all westbound flows originated from the Middle East (1.5 million b/d), mostly destined for the Americas, with the United States accounting for the majority of the total (75% of total flows). Europe was the destination for less than 12% of the flows.
The Cape of Good Hope is also an alternate sea route for vessels traveling westward that want to bypass the Gulf of Aden, Bab el-Mandeb Straits, and/or the Suez Canal. However, diverting vessels around the Cape of Good Hope increases costs and shipping time. For example, closure of the Suez Canal and the SUMED Pipeline would require oil tankers to divert around the Cape of Good Hope, adding approximately 2,700 miles to transit from Saudi Arabia to the United States, which would increase both costs and shipping time, according to the U.S. Department of Transportation.31 According to the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8—10 days to the United States.32
Table 7. Crude oil transit via the Cape of Good Hope, 2011-16million b/d201120122013201420152016Total flows126.96.36.199.95.15.8Eastbound188.8.131.52.84.14.3Westbound184.108.40.206.11.01.5Notes: Totals may not equal the sum of the components due to independent rounding.
Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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