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Pricing-in The Covid 19 Vaccine

In a few days, the bi-annual OPEC meeting will take place on November 30, leading into a wider OPEC+ meeting on December 30. This is what all the political jostling and negotiations currently taking place is leading up to, as the coalition of major oil producers under the OPEC+ banner decide on the next step of its historic and ambitious supply control plan. Designed to prop up global oil prices by managing supply, a postponement of the next phase in the supply deal is widely expected. But there are many cracks appearing beneath the headline.

A quick recap. After Saudi Arabia and Russia triggered a price war in March 2020 that led to a collapse in oil prices (with US crude prices briefly falling into negative territory due to the technical quirk), OPEC and its non-OPEC allies (known collectively as OPEC+) agreed to a massive supply quota deal that would throttle their production for 2 years. The initial figure was 10 mmb/d, until Mexico’s reticence brought that down to 9.7 mmb/d. This was due to fall to 7.7 mmb/d by July 2020, but soft demand forced a delay, while Saudi Arabia led the charge to ensure full compliance from laggards, which included Iraq, Nigeria and (unusually) the UAE. The next tranche will bring the supply control ceiling down to 5.7 mmb/d. But given that Covid-19 is still raging globally (despite promising vaccine results), this might be too much too soon. Yes, prices have recovered, but at US$40/b crude, this is still not sufficient to cover the oil-dependent budgets of many OPEC+ nations. So a delay is very likely.

But for how long? The OPEC+ Joint Technical Committee panel has suggested that the next step of the plan (which will effectively boost global supply by 2 mmb/d) be postponed by 3-6 months. This move, if adopted, will have been presaged by several public statements by OPEC+ leaders, including a pointed comment from OPEC Secretary General Mohammad Barkindo that producers must be ready to respond to ‘shifts in market fundamentals’.

On the surface, this is a necessary move. Crude prices have rallied recently – to as high as US$45/b – on positive news of Covid-19 vaccines. Treatments from Pfizer, Moderna and the Oxford University/AstraZeneca have touted 90%+ effectiveness in various forms, with countries such as the US, Germany and the UK ordering billions of doses and setting the stage for mass vaccinations beginning December. Life returning to a semblance of normality would lift demand, particularly in key products such as gasoline (as driving rates increase) and jet fuel (allowing a crippled aviation sector to return to life). Underpinning the rally is the understanding that OPEC+ will always act in the market’s favour, carefully supporting the price recovery. But there are already grouses among OPEC members that they are doing ‘too much’. Led by Saudi Arabia, the draconian dictates of meeting full compliance to previous quotas have ruffled feathers, although most members have reluctantly attempt to abide by them. But there is a wider existential issue that OPEC+ is merely allowing its rivals to resuscitate and leapfrog them once again; the US active oil rig count by Baker Hughes has reversed a chronic decline trend, as WTI prices are at levels above breakeven for US shale.

Complaints from Iran, Iraq and Nigeria are to be expected, as is from Libya as it seeks continued exemption from quotas due to the legacy of civil war even though it has recently returned to almost full production following a truce. But grievance is also coming from an unexpected quarter: the UAE. A major supporter in the Saudi Arabia faction of OPEC, reports suggest that the UAE (led by the largest emirate, Abu Dhabi) are privately questioning the benefit of remaining in OPEC. Beset by shrivelling oil revenue, the Emiratis have been grumbling about the fairness of their allocated quota as they seek to rebuild their trade-dependent economy. There has been suggestion that the Emiratis could even leave OPEC if decisions led to a net negative outcome for them. Unlike the Qatar exit, this will not just be a blow to OPEC as a whole, questioning its market relevance but to Saudi Arabia’s lead position, as it loses one of its main allies, reducing its negotiation power. And if the UAE leaves, Kuwait could follow, which would leave the Saudis even more isolated.

This could be a tactic to increase the volume of the UAE’s voice in OPEC+, which has been dominated by Saudi Arabia and Russia. But it could also be a genuine policy shift. Either way, it throws even more conundrums onto a delicate situation that could undermine an already fragile market. Despite the positive market news led by Covid-19 vaccines and demand recovery in Asia, American crude oil inventories in Cushing are now approaching similar high levels last seen in April (just before the WTI crash) while OPEC itself has lowered its global demand forecast for 2020 by 300,000 b/d. That’s dangerous territory to be treading in, especially if members of the OPEC+ club are threatening to exit and undermine the pack. A postponement of the plan seems inevitable on December 1 at this point, but it is what lies beyond the immediate horizon that is the true threat to OPEC+.

Market Outlook:

  • Crude price trading range: Brent – US$44-46/b, WTI – US$42-44/b
  • More positive news on Covid-19 vaccines have underpinned a crude price rally despite worrying signs of continued soft demand and inventory build-ups
  • Pfizer’s application for emergency approval of its vaccine is paving the way for mass vaccinations to begin soon, with some experts predicting that the global economy could return to normality in Q2 2021
  • Market observers are predicting a delay in the OPEC+ supply quota schedule, but the longer timeline for the club’s plan – which is set to last until April 2022 – may have to be brought forward to appease current dissent in the group

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EIA expects U.S. crude oil production to remain relatively flat through 2021

In the U.S. Energy Information Administration’s (EIA) November Short-Term Energy Outlook (STEO), EIA forecasts that U.S. crude oil production will remain near its current level through the end of 2021.

A record 12.9 million barrels per day (b/d) of crude oil was produced in the United States in November 2019 and was at 12.7 million b/d in March 2020, when the President declared a national emergency concerning the COVID-19 outbreak. Crude oil production then fell to 10.0 million b/d in May 2020, the lowest level since January 2018.

By August, the latest monthly data available in EIA’s series, production of crude oil had risen to 10.6 million b/d in the United States, and the U.S. benchmark price of West Texas Intermediate (WTI) crude oil had increased from a monthly average of $17 per barrel (b) in April to $42/b in August. EIA forecasts that the WTI price will average $43/b in the first half of 2021, up from our forecast of $40/b during the second half of 2020.

The U.S. crude oil production forecast reflects EIA’s expectations that annual global petroleum demand will not recover to pre-pandemic levels (101.5 million b/d in 2019) through at least 2021. EIA forecasts that global consumption of petroleum will average 92.9 million b/d in 2020 and 98.8 million b/d in 2021.

The gradual recovery in global demand for petroleum contributes to EIA’s forecast of higher crude oil prices in 2021. EIA expects that the Brent crude oil price will increase from its 2020 average of $41/b to $47/b in 2021.

EIA’s crude oil price forecast depends on many factors, especially changes in global production of crude oil. As of early November, members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) were considering plans to keep production at current levels, which could result in higher crude oil prices. OPEC+ had previously planned to ease production cuts in January 2021.

Other factors could result in lower-than-forecast prices, especially a slower recovery in global petroleum demand. As COVID-19 cases continue to increase, some parts of the United States are adding restrictions such as curfews and limitations on gatherings and some European countries are re-instituting lockdown measures.

EIA recently published a more detailed discussion of U.S. crude oil production in This Week in Petroleum.

OPEC members' net oil export revenue in 2020 expected to drop to lowest level since 2002

The U.S. Energy Information Administration (EIA) forecasts that members of the Organization of the Petroleum Exporting Countries (OPEC) will earn about $323 billion in net oil export revenues in 2020. If realized, this forecast revenue would be the lowest in 18 years. Lower crude oil prices and lower export volumes drive this expected decrease in export revenues.

Crude oil prices have fallen as a result of lower global demand for petroleum products because of responses to COVID-19. Export volumes have also decreased under OPEC agreements limiting crude oil output that were made in response to low crude oil prices and record-high production disruptions in Libya, Iran, and to a lesser extent, Venezuela.

OPEC earned an estimated $595 billion in net oil export revenues in 2019, less than half of the estimated record high of $1.2 trillion, which was earned in 2012. Continued declines in revenue in 2020 could be detrimental to member countries’ fiscal budgets, which rely heavily on revenues from oil sales to import goods, fund social programs, and support public services. EIA expects a decline in net oil export revenue for OPEC in 2020 because of continued voluntary curtailments and low crude oil prices.

The benchmark Brent crude oil spot price fell from an annual average of $71 per barrel (b) in 2018 to $64/b in 2019. EIA expects Brent to average $41/b in 2020, based on forecasts in EIA’s October 2020 Short-Term Energy Outlook (STEO). OPEC petroleum production averaged 36.6 million barrels per day (b/d) in 2018 and fell to 34.5 million b/d in 2019; EIA expects OPEC production to decline a further 3.9 million b/d to average 30.7 million b/d in 2020.

EIA based its OPEC revenues estimate on forecast petroleum liquids production—including crude oil, condensate, and natural gas plant liquids—and forecast values of OPEC petroleum consumption and crude oil prices.

EIA recently published a more detailed discussion of OPEC revenue in This Week in Petroleum.

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.

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.

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.