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Brent crude is once again flirting with the US$80/b level. By the time October begins, it is likely that Brent prices will be comfortably over the mark, pulling WTI prices up towards the same level. The last time crude prices surged (and sustained) above this level, US$80/b was identified as the level where demand destruction began, as countries and companies scaled back on oil usage. Since the price crash in 2015, demand has managed to pick up tremendously, in no small part due to cheap prices. Where do prices go from here? Can they return to the US$100/b level? That would be cheery news for oil firms, who are finally emerging from a tough slump, but it could also return us to the excesses of the previous cycle, repeating the same problems.
The direction for oil prices – at least for the foreseeable futures – is definitely up. The main thrust for this is Iran. Or rather, renewed American sanctions on Iran. Though the Trump administration’s aim to reduce Iranian crude exports to zero is probably a pipe dream – in no small part due to pushback from India and China – the sanctions will still manage to remove at least 1 million b/d from the market. At a time when Venezuela production is in a downward spiral and disruption continually threatens OPEC’s North African members, this supply risk is constantly pushing prices levels up. OPEC has vowed to turn on the spigots in association with its NOPEC partners, but not to a level that can offset all the losses, to appease members such as Iran and Iraq. This is unlikely to be revised drastically at the upcoming OPEC meeting in December. The US is not happy about the situation – witness President Trump’s flailing tweets – and the American Congress is considering an anti-cartel bill that could open OPEC to lawsuits, all to rectify a situation that it itself created.
Because of this, major oil trading houses and banks are predicting prices to rise even further. Goldman Sachs, which once famously predicted prices could spike to US$200/b during the 2008 boom, is curiously cautious in maintaining its prediction at a floor of US$80/b, as is Citibank. JP Morgan, however, expects Brent to hit US$85/b as early as November, on a path to rise to US$90/b. Trading houses are more bullish. Mercuria and Trafigura are both predicting US$100/b prices by early 2019 – citing the lack of spare capacity in the market to replace lost volumes. Even the shale rush in the US that has made America the world’s largest crude producer will not be enough to replace lost Iranian volumes in the short- and medium-term. Most analysts expect the Iranian losses to be at least 1 mmb/d, with some analysts predicting that Iranian exports would fall to just 700,000 b/d from 2.1 mmb/d last year, shipped mostly to China and to India, with land routes used to circumvent shipping and insurance sanctions.
At prices like this, one would expect oil producers to rush in to fill the gap. But pipeline infrastructure limitations in the Permian are hampering distribution to Gulf Coast export hubs, while promising upstream production in Guyana, Mexico and Australia are still far, far off from commercialisation. Meanwhile, vast new LNG facilities has come onstream, together with major natural gas finds, accelerating oil’s displacement by gas in key sectors such as power and petrochemicals. Meanwhile, oil firms expect the bonanza to continue; service firms, particularly deepwater-focused ones, are seeing enthusiastic signs, as firms push towards riskier projects made economical only at high oil prices. This has happened before, as most would remember, but the oil industry has a short memory. Where will crude prices go from here? Nobody can agree on the exact magnitude, but everyone agrees that the direction is up.
Factors influencing the rise to US$100/b oil:
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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.
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.
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.
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.
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.
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.
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:
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.
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.
