The following This Week in Petroleum articles were originally published throughout 2020. New feature articles of This Week in Petroleum will return on January 6, 2021. The retail price and inventory paragraphs, charts, and tables accompanying the feature article have been updated to reflect data from the latest Weekly Petroleum Status Report for the week ending December 25, 2020.
Published March 25, 2020: Oil market volatility is at an all-time high
Crude oil prices have fallen significantly since the beginning of 2020, largely driven by the economic contraction caused by the 2019 novel coronavirus disease (COVID19) and a sudden increase in crude oil supply following the suspension of agreed production cuts among the Organization of the Petroleum Exporting Countries (OPEC) and partner countries. With falling demand and increasing supply, the front-month price of the U.S. benchmark crude oil West Texas Intermediate (WTI) fell from a year-to-date high closing price of $63.27 per barrel (b) on January 6 to a year-to-date low of $20.37/b on March 18 (Figure 1), the lowest nominal crude oil price since February 2002.
Published on April 22, 2020: WTI crude oil futures prices fell below zero because of low liquidity and limited available storage
On Monday, April 20, 2020, New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) crude oil front-month futures prices fell below zero dollars per barrel (b)—at one point, trading at -$40.32/b (Figure 2)—and remained below zero for part of the following trading day. Monday marked the first time the price for the WTI futures contract fell below zero since trading began in 1983. Negative prices in commodity markets are very rare, but when they occur they typically indicate high transactions costs and significant infrastructure constraints. In this case, the WTI front-month futures contract was for May 2020 delivery, and the contract was set to expire on April 21, 2020. Unless they have made other arrangements ahead of time, market participants that hold WTI futures contracts to expiration must take physical delivery of WTI crude oil in Cushing, Oklahoma. Typically, most market participants close any futures contracts ahead of expiration through cash settlement in order to avoid taking physical delivery, and only about 1% of contracts are physically settled. The extreme market events of April 20 and April 21 were driven by several factors, including the inability of contract holders to find other market participants to sell the futures contracts. In addition, in this case, the scarcity of available crude oil storage meant several market participants sold their futures contracts at negative prices, in effect paying a counterparty to close out of the contracts.
Published on June 3, 2020: March saw major declines in U.S. demand for petroleum products
On March 13, 2020, the President declared a national emergency in the United States in response to concerns regarding the 2019 novel coronavirus disease (COVID-19) outbreak. Reduced economic activity and stay-at-home orders aimed at slowing the spread of COVID-19 led to a sharp decrease in demand for petroleum products. Because refiners responded faster to reduced demand than crude oil producers, crude oil inventories increased as refinery runs fell. Despite reflecting only one-half of a month under the declared national emergency, the U.S. Energy Information Administration’s (EIA) March Petroleum Supply Monthly (PSM) data show the early effects of the COVID-19 mitigation efforts.
U.S. gross inputs into refineries fell by 670,000 barrels per day (b/d) (4.1%) from February to March to average 15.8 million b/d, the lowest monthly level since October 2015 (Figure 3). However, the refinery input decreases were not the same in every region of the United States. Gross inputs in the U.S. Gulf Coast (Petroleum Administration for Defense District, or PADD, 3), home to more than half of U.S. refining capacity, increased by 43,000 b/d (0.5%) from February to March, likely as a result of increased runs after maintenance in February. However, the year-over-year change also indicates relatively strong refinery runs in the Gulf Coast, with March 2020 runs averaging 193,000 b/d more than 2019 levels. Gross inputs in the Gulf Coast may have remained elevated compared with the U.S. average because refiners in the Gulf Coast produce petroleum products for consumption in other areas of the country and for export.
Published July 29, 2020: COVID-19’s impact on global commercial jet fuel demand has been significant and uneven
Although COVID-19 mitigation efforts have reduced demand for all transportation fuels, demand for jet fuel has likely declined the most in relative terms. For instance, in the United States—the world’s largest jet fuel consumer—average jet fuel product supplied (a proxy for consumption) in June 2020 was 41% of what it had been in June 2019, compared with 86% for gasoline and 88% for diesel fuel, according to the July edition of the U.S. Energy Information Administration’s (EIA) Short-Term Energy Outlook (STEO).
To estimate global changes in jet fuel consumption, EIA recently began using data from aviation company Cirium that detail each scheduled commercial passenger flight since January 2019, including the type of aircraft flown and its route. Using data on each flight’s origin and destination, EIA calculated the great-circle distance (which measures the straight-line distance between two points along the earth’s surface) for each flight. EIA then increased that distance by 10% per flight to compensate for the excess distance airplanes fly on average relative to the shortest, optimized path. After factoring in the average fuel efficiency of each flight’s aircraft (including fuel used during takeoff, landing, and taxiing), EIA estimated the volume of jet fuel consumed by each flight and summed these flights to estimate the volume of jet fuel consumed globally by commercial passenger flights (Figure 4).
Published August 19, 2020: U.S. refineries respond to record-low demand by decreasing inputs to certain downstream units
From March 2020 (when a national emergency was declared) to April 2020, U.S. demand for gasoline, jet fuel, and diesel fuel decreased. Jet fuel and gasoline demand (as measured by product supplied) dropped the most, decreasing by 50% and 25%, respectively. Diesel fuel demand decreased less than gasoline and jet fuel demand, falling 10% from March to April. Stay-at-home orders and travel restrictions affected gasoline and jet fuel demand more than diesel fuel demand. The decline in gasoline and jet fuel consumption was the result of consumers travelling less. But because diesel fuel is used extensively in trucking, increased demand for home delivery and distribution of necessary goods and services likely supported the volumes of distillate product supplied.
Refiners responded to the changes in transportation fuel demand by decreasing refinery runs, with the largest decreases seen in units focused on gasoline production. Gross inputs to atmospheric distillation units (ADU) in April 2020 were 3.4 million barrels per day (b/d) (21%) lower than the five-year (2015–19) average, and gross inputs to ADUs in May 2020 were 3.6 million b/d (21%) lower than the five-year average (Figure 5). Compared with ADUs and other downstream units, inputs to catalytic crackers, associated with gasoline production in a refinery, had the second-largest change on a volume basis from the five-year averages in April and May, averaging 1.6 million b/d and 1.4 million b/d lower, respectively. On a percentage basis, the decrease in inputs to catalytic crackers was the largest out of all units; inputs in April decreased 32% from the five-year average, and inputs in May decreased 29% from the five-year average.
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price increased nearly 2 cents to $2.24 per gallon on December 28, almost 33 cents lower than the same time last year. The Midwest price increased more than 5 cents to $2.17 per gallon, the West Coast price increased nearly 2 cents to $2.79 per gallon, the East Coast price increased nearly 1 cent to $2.20 per gallon, and the Rocky Mountain price increased less than 1 cent, remaining virtually unchanged at $2.19 per gallon. The Gulf Coast price decreased less than 1 cent, remaining virtually unchanged at $1.93 per gallon.
The U.S. average diesel fuel price increased nearly 2 cents to $2.64 per gallon on December 28, 43 cents lower than a year ago. The Midwest price increased nearly 3 cents to $2.59 per gallon, the West Coast price increased nearly 2 cents to $3.11 per gallon, the Gulf Coast increased more than 1 cent to $2.39 per gallon, and the East Coast and Rocky Mountain prices each increased nearly 1 cent to $2.66 per gallon and $2.59 per gallon, respectively.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 6.5 million barrels last week to 75.1 million barrels as of December 25, 2020, 2.3 million barrels (3.0%) less than the five-year (2015-19) average inventory levels for this same time of year. Gulf Coast, Midwest, East Coast, and Rocky Mountain/West Coast inventories declined by 3.5 million barrels, 1.6 million barrels, 1.0 million barrels, and 0.3 million barrels, respectively.
Residential heating fuel prices increase
As of December 28, 2020, residential heating oil prices averaged more than $2.44 per gallon, nearly 2 cents per gallon above last week’s price but almost 64 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged nearly $1.61 per gallon, almost 2 cents per gallon below last week’s price and more than 55 cents per gallon lower than last year.
Residential propane prices averaged more than $1.97 per gallon, 3 cents per gallon above last week’s price but nearly 4 cents per gallon below last year’s price. Wholesale propane prices averaged almost $0.84 per gallon, less than 1 cent per gallon lower last week’s price but nearly 13 cents per gallon above last year’s price.
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Two acquisitions in the energy sector were announced in the last week that illustrate the growing divergence in approaching the future of oil and gas between Europe and the USA. In France, Total announced that it had bought Fonroche Biogaz, the market leader in the production of renewable gas in France. In North America, ConocoPhillips completed its acquisition of Concho Resources, deepening the upstream major’s foothold into the lucrative Permian Basin and its shale riches. One is heading towards renewables, and the other is doubling down on conventional oil and gas.
What does this say about the direction of the energy industry?
Total’s move is unsurprising. Like almost all of its European peers operating in the oil and gas sector, Total has announced ambitious targets to become carbon-neutral by 2050. It is an ambition supported by the European population and pushed for by European governments, so in that sense, Total is following the wishes of its investors and stakeholders – just like BP, Shell, Repsol, Eni and others are doing. Fonroche Biogaz is therefore a canny acquisition. The company designs, builds and operates anaerobic digestion units that convert organic waste such as farming manure into biomethane to serve a gas feedstock for power generation. Fonroche Biogaz already has close to 500 GWh of installed capacity through seven power generation units with four in the pipeline. This feeds into Total’s recent moves to expand its renewable power generation capacity, with the stated intention of increasing the group’s biomethane capacity to 1.5 terawatts per hour (TWh) by 2025. Through this, Total vaults into a leading position within the renewable gas market in Europe, which is already active through affiliates such as Méthanergy, PitPoint and Clean Energy.
In parallel to this move, Total also announced that it has decided not to renew its membership in the American Petroleum Institute for 2021. Citing that it is only ‘partially aligned’ with the API on climate change issues in the past, Total has now decided that those positions have now ‘diverged’ particularly on rolling back methane emission regulations, carbon pricing and decarbonising transport. The French supermajor is not alone in its stance. BP, which has ditched the supermajor moniker in favour of turning itself into a clean energy giant, has also expressed reservations over the API’s stance over climate issues, and may very well choose to resign from the trade group as well. Other European upstream players might follow suit.
However, the core of the API will remain American energy firms. And the stance among these companies remains pro-oil and gas, despite shareholder pressure to bring climate issues and clean energy to the forefront. While the likes of ExxonMobil and Chevron have balanced significant investments into prolific shale patches in North America with public overtures to embrace renewables, no major US firm has made a public commitment to a carbon-neutral future as their European counterparts have. And so ConocoPhillips acquisition of Concho Resources, which boosts its value to some US$60 billion is not an outlier, but a preview of the ongoing consolidation happening in US shale as the free-for-all days give way to big boy acquisitions following the price-upheaval there since 2019.
That could change. In fact, it will change. The incoming Biden administration marks a significant break from the Trump administration’s embrace of oil and gas. Instead of opening of protected federal lands to exploration, especially in Alaska and sensitive coastal areas and loosening environmental regulations, the US will now pivot to putting climate change at the top of the agenda. Although political realities may water it down, the progressive faction of the Democrats are pushing for a Green New Deal embracing sustainability as the future for the US. Biden has already hinted that he may cancel the controversial and long-running Keystone XL pipeline via executive order on his first day in the office. His nominees for key positions including the Department of the Interior, Department of Energy, Environmental Protection Agency and Council on Environmental Quality suggest that there will be a major push on low-carbon and renewable initiatives, at least for the next 4 years. A pledge to reach net zero fossil fuel emissions from the power sector by 2035 has been mooted. More will come.
The landscape is changing. But the two approaches still apply, the aggressive acceleration adopted by European majors, and the slower movement favoured by US firms. Political changes in the USA might hasten the change, but it is unlikely that convergence will happen anytime soon. There is room in the world for both approaches for now, but the future seems inevitable. It just depends on how energy companies want to get there.
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In its January Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global demand for petroleum liquids will be greater than global supply in 2021, especially during the first quarter, leading to inventory draws. As a result, EIA expects the price of Brent crude oil to increase from its December 2020 average of $50 per barrel (b) to an average of $56/b in the first quarter of 2021. The Brent price is then expected to average between $51/b and $54/b on a quarterly basis through 2022.
EIA expects that growth in crude oil production from members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) will be limited because of a multilateral agreement to limit production. Saudi Arabia announced that it would voluntarily cut production by an additional 1.0 million b/d during February and March. Even with this cut, EIA expects OPEC to produce more oil than it did last year, forecasting that crude oil production from OPEC will average 27.2 million b/d in 2021, up from an estimated 25.6 million b/d in 2020.
EIA forecasts that U.S. crude oil production in the Lower 48 states—excluding the Gulf of Mexico—will decline in the first quarter of 2021 before increasing through the end of 2022. In 2021, EIA expects crude oil production in this region will average 8.9 million b/d and total U.S. crude oil production will average 11.1 million b/d, which is less than 2020 production.
EIA expects that responses to the recent rise in COVID-19 cases will continue to limit global oil demand in the first half of 2021. Based on global macroeconomic forecasts from Oxford Economics, however, EIA forecasts that global gross domestic product will grow by 5.4% in 2021 and by 4.3% in 2022, leading to energy consumption growth. EIA forecasts that global consumption of liquid fuels will average 97.8 million barrels per day (b/d) in 2021 and 101.1 million b/d in 2022, only slightly less than the 2019 average of 101.2 million b/d.
EIA expects global inventory draws will contribute to forecast rising crude oil prices in the first quarter of 2021. Despite rising forecast crude oil prices in early 2021, EIA expects upward price pressure will be limited through the forecast period because of high global oil inventory, surplus crude oil production capacity, and stock draws decreasing after the first quarter of 2021. EIA forecasts Brent crude oil prices will average $53/b in both 2021 and 2022.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
You can find more information on EIA’s expectations for changes in global petroleum liquids production, consumption, and crude oil prices in EIA’s latest This Week in Petroleum article and its January STEO.
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