EXECUTIVE SUMMARY

• The COVID-19 pandemic and the energy transition will reduce long-term oil demand levels and accelerate the period at which it peaks. Crude oil demand was reset at a lower level following a 10 MMb/d decline in 2020. In our new long-term outlook, crude oil demand continues to grow to 2033, peaking at about 81 MMb/d, which is 5.2 MMb/d lower and four years earlier than the peak we foresaw in our outlook from 2020. Efficiency trends, alternative fuels and drivetrains, government policies, and changing demographics limit the need for fossil petroleum-based products. As these trends accelerate, crude oil demand will decline to about 80 MMb/d by 2040 (approximately the same level as 2019 pre-pandemic levels).
  
  
• Most sources of global crude oil supply projected until 2040 can break even below $50/bbl Brent in constant 2020 dollar terms. Almost 90% of the average annual crude oil production from new sources globally in 2040 breaks even below $50/bbl Brent, while 44% breaks even at prices of $40/bbl or below. However, we expect that both conventional and tight oil projects that break even at $50/bbl and above will still be needed to meet demand and offset base declines.
  
  
• The Middle East and US tight oil account for about half of global average annual crude oil production from new sources in 2040, but the Middle East continues to enjoy the lowest average break-even prices (BEPs). The average weighted Middle East BEP is about $22/bbl Brent, whereas the average US Permian well requires about $46/bbl Brent. The overall global supply stack remains relatively flat, with the majority of supply expected to break even between $40/bbl and $50/bbl.
  
  
• Some volumes of oil supply that break even at prices higher than $50/bbl will still be produced. The oil price environment will not be linear; rather, oil prices will cycle above and below the long-term averages we have projected. There will be projects that investors bring to life when prices are higher than average. Moreover, the economics of some projects to be brought onstream will only be known in retrospect, such as wells that do not perform as well as expected after they have been completed.
  
  
• Upstream investment shifts away from greenfield megaprojects. As oil demand growth decelerates and the energy transition accelerates, an investment shift is under way in new upstream projects. Upstream operators have shifted from expensive, large-scale, single-project investments to small- or medium-scale onshore and subsea tieback projects, and those with multiphase expansion opportunities with economical break-even prices are expected to fill in the majority of new source conventional crude oil production over the next two decades.

Key Changes from last year

• Average BEPs for US tight oil plays have decreased owing to many factors, including a higher assumed price received for natural gas (from $1.50/Mcf to $3.00/Mcf, Henry Hub basis), productivity increases in some oil plays, and lower capex per well due to the COVID-19 impact on rig and frac crew counts.
  
  
• In terms of new conventional offshore production, the curve now includes low-cost Guyana offshore with a BEP of $38/bbl. BEPs are lower for India (a $14/bbl decrease) and China (a $11/bbl decrease). These decreases are partially offset by higher BEPs for Vietnam (a $6/bbl increase), as well as Kazakhstan, Nigeria, and Thailand (a $5/bbl increase for each).
  
  
• For conventional onshore projects, two regions have materially lower BEPs—China and India (decreases of $11/bbl and $9/bbl, respectively)—owing to more precise cost data obtained for these projects. All other onshore projects have higher BEPs.

Posted 10 September 2021 by Aaron Brady, Vice President, Energy Oil Market Services, S&P Global Commodity Insights