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Last Updated: June 6, 2019
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U.S. Gulf Coast crude oil imports averaged 1.8 million barrels per day (b/d) in March 2019, the lowest level since March 1986 and significantly lower than the peak of 6.6 million b/d in March 2007. Preliminary weekly data indicate that Gulf Coast crude oil imports have averaged about 1.9 million b/d through April and May (Figure 1). Falling crude oil imports into the U.S. Gulf Coast so far in 2019 are the result of both recent events and continuing longer-term trends. Recently, sanctions on Venezuelan imports and heavy refinery maintenance have reduced imports. At the same time, imports to the Gulf Coast have also decreased because of sharp declines in imports from the Organization of the Petroleum Exporting Countries (OPEC) following an agreement among members to reduce production and because imports are being replaced by increased production of domestic crude oil. Together, these trends have fundamentally changed how the Gulf Coast region is supplied with crude oil. In the past five consecutive months, the U.S. Gulf Coast has exported more crude oil than it imported (net exports), and since 2015, it has consistently received more crude oil from other regions of the United States than it has sent to other regions (net receipts).

Figure 1. U.S. Gulf Coast crude oil imports

Gulf Coast crude oil imports are typically lower in the early months of the year as refineries reduce runs as part of their seasonal maintenance. This year, planned maintenance activity was higher than usual. The four-week average of gross refinery inputs in the Gulf Coast fell from 9.6 million b/d for the week ending January 4, higher than the five-year (2014-18) maximum and 648,000 b/d higher than the five-year average, to a low of about 8.6 million b/d from mid-February until mid-April. Although 8.6 million b/d of gross refinery inputs is more than the Gulf Coast’s five-year average level for the period, eight consecutive weeks of relatively flat refinery runs is longer than normal during refinery maintenance at this time of year. This extended period of lower refinery runs for longer in the early months of 2019 reduced the need for crude oil imports, contributing to the more-than-three-decade-low crude oil imports during this period.

Around the same time, the U.S. government announced additional sanctions on Venezuela that included limitations on crude oil imports from Venezuela. In 2018, 20% of all Gulf Coast crude oil imports were from Venezuela, an annual average of 498,000 b/d. The Gulf Coast was the destination for 98% of all U.S. imports of Venezuelan crude oil in 2018. Because of the imposition of sanctions, refiners in the Gulf Coast sharply reduced imports of Venezuelan crude oil. Between January and March 2019, Gulf Coast imports of crude oil from Venezuela fell by 498,000 b/d to 47,000 b/d in March. As a result of the Gulf Coast reductions, U.S. four-week average imports from Venezuela fell from 603,000 b/d for the week ending January 25 to 12,000 b/d for the week ending May 31 (Figure 2).

Figure 2. U.S. crude oil imports from Venezuela

An additional change in Gulf Coast crude oil imports occurred following a November 2016 agreement by OPEC members to cut crude oil production. As a result of the production cuts, many OPEC members reduced exports to the United States in favor of growing markets in Asia. One year after the production-cut agreement, crude oil imports from OPEC processed at Gulf Coast refineries had fallen 562,000 b/d from 2.1 million b/d in November 2016 to 1.5 million b/d in November 2017. Imports of crude oil from OPEC members into the Gulf Coast continued to decline, falling to 1.4 million b/d in 2018 and down to 513,000 b/d in March 2019 (Figure 3).

Figure 3. U.S. Gulf Coast processed crude oil import sources

Before the OPEC production cuts in 2016, the Gulf Coast had already started reducing crude oil imports because of rising domestic production and changes in domestic crude oil pipeline infrastructure. Gulf Coast crude oil production increased from 2.7 million b/d in 2008 to 7.9 million b/d in March 2019. Much of this increased crude oil production was of light sweet crude oil that allowed Gulf Coast refineries to reduce imports of light sweet crude oil from foreign sources. Then pipeline infrastructure that once took imported crude oil from the Gulf Coast and delivered it to other regions of the United States was reversed, instead delivering increased domestic crude oil production and imports from Canada to Gulf Coast refineries. By 2015, this reversal meant that the Gulf Coast changed from being a net shipper of crude oil to other U.S. regions to being a net recipient. More recently, as imports have declined and crude oil exports have expanded, the Gulf Coast actually exported more crude oil than it imported for five consecutive months (Figure 4).

Figure 4. U.S. Gulf Coast crude oil supply/demand balance

Because of all these changes combined, foreign-sourced crude oil receipts at Gulf Coast refineries accounted for an average of 36% of Gulf Coast refinery crude oil inputs in 2018, compared with 73% in 2008. The sources of those imports have also changed, with Canada and Mexico accounting for 54% of all imported crude oil processed in Gulf Coast refineries in March, representing a new high.

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price fell nearly 2 cents from the previous week to $2.81 per gallon on June 3, more than 13 cents lower than the same time last year. The Gulf Coast price fell nearly 5 cents to $2.42 per gallon, the West Coast price fell nearly 4 cents to $3.60 per gallon, and the East Coast price fell more than 3 cents to $2.66 per gallon. The Midwest price rose more than 3 cents to $2.75 per gallon and the Rocky Mountain price increased slightly, remaining at $2.98 per gallon.

The U.S. average diesel fuel price fell nearly 2 cents to $3.14 per gallon on June 3, nearly 15 cents lower than a year ago. The West Coast price fell more than 2 cents to $3.76 per gallon, the Rocky Mountain and Gulf Coast prices each fell nearly 2 cents to $3.16 per gallon and $2.88 per gallon, respectively, and the Midwest and East Coast prices each fell over 1 cent to $3.03 per gallon and $3.15 per gallon, respectively.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 2.5 million barrels last week to 68.3 million barrels as of May 31, 2019, 9.1 million barrels (15.4%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast inventories increased by 1.2 million barrels, and Midwest and East Coast inventories each increased by 0.7 million barrels. Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 7.2% of total propane/propylene inventories.

Canada crude oil exports imports Gulf Coast Mexico non-OPEC OPEC PADD 3 refining Venezuela
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The United States consumed a record amount of renewable energy in 2019

In 2019, consumption of renewable energy in the United States grew for the fourth year in a row, reaching a record 11.5 quadrillion British thermal units (Btu), or 11% of total U.S. energy consumption. The U.S. Energy Information Administration’s (EIA) new U.S. renewable energy consumption by source and sector chart published in the Monthly Energy Review shows how much renewable energy by source is consumed in each sector.

In its Monthly Energy Review, EIA converts sources of energy to common units of heat, called British thermal units (Btu), to compare different types of energy that are more commonly measured in units that are not directly comparable, such as gallons of biofuels compared with kilowatthours of wind energy. EIA uses a fossil fuel equivalence to calculate primary energy consumption of noncombustible renewables such as wind, hydro, solar, and geothermal.

U.S. renewable energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Wind energy in the United States is almost exclusively used by wind-powered turbines to generate electricity in the electric power sector, and it accounted for about 24% of U.S. renewable energy consumption in 2019. Wind surpassed hydroelectricity to become the most-consumed source of renewable energy on an annual basis in 2019.

Wood and waste energy, including wood, wood pellets, and biomass waste from landfills, accounted for about 24% of U.S. renewable energy use in 2019. Industrial, commercial, and electric power facilities use wood and waste as fuel to generate electricity, to produce heat, and to manufacture goods. About 2% of U.S. households used wood as their primary source of heat in 2019.

Hydroelectric power is almost exclusively used by water-powered turbines to generate electricity in the electric power sector and accounted for about 22% of U.S. renewable energy consumption in 2019. U.S. hydropower consumption has remained relatively consistent since the 1960s, but it fluctuates with seasonal rainfall and drought conditions.

Biofuels, including fuel ethanol, biodiesel, and other renewable fuels, accounted for about 20% of U.S. renewable energy consumption in 2019. Biofuels usually are blended with petroleum-based motor gasoline and diesel and are consumed as liquid fuels in automobiles. Industrial consumption of biofuels accounts for about 36% of U.S. biofuel energy consumption.

Solar energy, consumed to generate electricity or directly as heat, accounted for about 9% of U.S. renewable energy consumption in 2019 and had the largest percentage growth among renewable sources in 2019. Solar photovoltaic (PV) cells, including rooftop panels, and solar thermal power plants use sunlight to generate electricity. Some residential and commercial buildings heat with solar heating systems.

October, 20 2020
Natural gas generators make up largest share of U.S. electricity generation capacity

operating natural-gas fired electric generating capacity by online year

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Based on the U.S. Energy Information Administration's (EIA) annual survey of electric generators, natural gas-fired generators accounted for 43% of operating U.S. electricity generating capacity in 2019. These natural gas-fired generators provided 39% of electricity generation in 2019, more than any other source. Most of the natural gas-fired capacity added in recent decades uses combined-cycle technology, which surpassed coal-fired generators in 2018 to become the technology with the most electricity generating capacity in the United States.

Technological improvements have led to improved efficiency of natural gas generators since the mid-1980s, when combined-cycle plants began replacing older, less efficient steam turbines. For steam turbines, boilers combust fuel to generate steam that drives a turbine to generate electricity. Combustion turbines use a fuel-air mixture to spin a gas turbine. Combined-cycle units, as their name implies, combine these technologies: a fuel-air mixture spins gas turbines to generate electricity, and the excess heat from the gas turbine is used to generate steam for a steam turbine that generates additional electricity.

Combined-cycle generators generally operate for extended periods; combustion turbines and steam turbines are typically only used at times of peak load. Relatively few steam turbines have been installed since the late 1970s, and many steam turbines have been retired in recent years.

natural gas-fired electric gnerating capacity by retirement year

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Not only are combined-cycle systems more efficient than steam or combustion turbines alone, the combined-cycle systems installed more recently are more efficient than the combined-cycle units installed more than a decade ago. These changes in efficiency have reduced the amount of natural gas needed to produce the same amount of electricity. Combined-cycle generators consume 80% of the natural gas used to generate electric power but provide 85% of total natural gas-fired electricity.

operating natural gas-fired electric generating capacity in selected states

Source: U.S. Energy Information Administration, Annual Electric Generator Inventory

Every U.S. state, except Vermont and Hawaii, has at least one utility-scale natural gas electric power plant. Texas, Florida, and California—the three states with the most electricity consumption in 2019—each have more than 35 gigawatts of natural gas-fired capacity. In many states, the majority of this capacity is combined-cycle technology, but 44% of New York’s natural gas capacity is steam turbines and 67% of Illinois’s natural gas capacity is combustion turbines.

October, 19 2020
EIA’s International Energy Outlook analyzes electricity markets in India, Africa, and Asia

Countries that are not members of the Organization for Economic Cooperation and Development (OECD) in Asia, including China and India, and in Africa are home to more than two-thirds of the world population. These regions accounted for 44% of primary energy consumed by the electric sector in 2019, and the U.S. Energy Information Administration (EIA) projected they will reach 56% by 2050 in the Reference case in the International Energy Outlook 2019 (IEO2019). Changes in these economies significantly affect global energy markets.

Today, EIA is releasing its International Energy Outlook 2020 (IEO2020), which analyzes generating technology, fuel price, and infrastructure uncertainty in the electricity markets of Africa, Asia, and India. A related webcast presentation will begin this morning at 9:00 a.m. Eastern Time from the Center for Strategic and International Studies.

global energy consumption for power generation

Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)

IEO2020 focuses on the electricity sector, which consumes a growing share of the world’s primary energy. The makeup of the electricity sector is changing rapidly. The use of cost-efficient wind and solar technologies is increasing, and, in many regions of the world, use of lower-cost liquefied natural gas is also increasing. In IEO2019, EIA projected renewables to rise from about 20% of total energy consumed for electricity generation in 2010 to the largest single energy source by 2050.

The following are some key findings of IEO2020:

  • As energy use grows in Asia, some cases indicate more than 50% of electricity could be generated from renewables by 2050.
    IEO2020 features cases that consider differing natural gas prices and renewable energy capital costs in Asia, showing how these costs could shift the fuel mix for generating electricity in the region either further toward fossil fuels or toward renewables.
  • Africa could meet its electricity growth needs in different ways depending on whether development comes as an expansion of the central grid or as off-grid systems.
    Falling costs for solar photovoltaic installations and increased use of off-grid distribution systems have opened up technology options for the development of electricity infrastructure in Africa. Africa’s power generation mix could shift away from current coal-fired and natural gas-fired technologies used in the existing central grid toward off-grid resources, including extensive use of non-hydroelectric renewable generation sources.
  • Transmission infrastructure affects options available to change the future fuel mix for electricity generation in India.
    IEO2020 cases demonstrate the ways that electricity grid interconnections influence fuel choices for electricity generation in India. In cases where India relies more on a unified grid that can transmit electricity across regions, the share of renewables significantly increases and the share of coal decreases between 2019 and 2050. More limited movement of electricity favors existing in-region generation, which is mostly fossil fuels.

IEO2020 builds on the Reference case presented in IEO2019. The models, economic assumptions, and input oil prices from the IEO2019 Reference case largely remained unchanged, but EIA adjusted specific elements or assumptions to explore areas of uncertainty such as the rapid growth of renewable energy.

Because IEO2020 is based on the IEO2019 modeling platform and because it focuses on long-term electricity market dynamics, it does not include the impacts of COVID-19 and related mitigation efforts. The Annual Energy Outlook 2021 (AEO2021) and IEO2021 will both feature analyses of the impact of COVID-19 mitigation efforts on energy markets.

Asia infographic, as described in the article text


Source: U.S. Energy Information Administration, International Energy Outlook 2020 (IEO2020)
Note: Click to enlarge.

With the IEO2020 release, EIA is publishing new Plain Language documentation of EIA’s World Energy Projection System (WEPS), the modeling system that EIA uses to produce IEO projections. EIA’s new Handbook of Energy Modeling Methods includes sections on most WEPS components, and EIA will release more sections in the coming months.

October, 16 2020