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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
