1 This decline is net of in-fill drilling, and other work done to fields that are not classified as major projects.
2 Does not include shallow water.
3 Other includes onshore conventional excluding OPEC Gulf, oil sands, heavy oil, and unconventional gas.
Source: McKinsey Energy Insights
Global oil supply growth 2016-2030
Figure 3. By 2030, E&P companies will need
to add 16 MMb/d of new offshore production
from unsanctioned projects to meet demand.
Shale oil Offshore 2030:
5. 4 2. 6
7. 2 106.2
- 37. 3
20 Offshore January 2018 • www.offshore-mag.com
global oil stack declined by in the five years
before the price collapse.
Spending cuts are expected to cause a 50-
60% decrease in oil volumes coming online
from new projects in the next three to five
years, compared to the 2010-14 average. As
with brownfield projects, the greenfield pipeline for the next few years has been significantly reduced due to the lack of investment
since 2014, especially for shallow water devel-
opments. In fact, only half as many projects
received final investment decisions (FIDs) in
2016 as did in 2014.
Deepwater was the only resource type
where FIDs stayed relatively strong thanks
to significant cost compression, as break-
even levels came down by 30-40%. Projects
like Mad Dog Phase 2 further lowered their
break-evens by simplification of design and
standardization, by using existing best practic-
es; and making use of existing infrastructure
(Mad Dog 2 used the design of the existing
Global FID numbers, including onshore,
have already started to recover. Yet excluding
some major deepwater projects, what is currently in the immediate offshore pipeline is
mainly smaller, lower-cost projects. As a result,
the production volumes set to come online in
the next two to three years are considerably
lower than what we saw come online in 2014.
Overall, we assume that investment cuts will
result in 50-60% lower volumes coming online
from new projects in the next three to five
years, compared to the 2010-14 average. This
is a problem for an industry that is already fac-
ing accelerated declines from existing fields.
The 13-16 MMb/d gap in supply by 2030
will create an opportunity for new cost-compet-
itive deepwater projects. The reduced number
of greenfield projects combined with higher
decline rates likely means that the industry
will be challenged in producing enough fu-
ture oil from current approved projects to
sufficiently meet rising demand.
Projects that reached FID before 2014 –
including mega-projects such as Lula and
Golden Eagle – will cover 60% of the anticipated supply gap in 2020-21, but projects approved since 2014 are not sufficient to cover
the remaining 40%. If no new projects were
sanctioned going forward, we would expect
a supply gap of approximately 35 MMb/d to
materialize by 2030.
The supply gap is unlikely to be fully offset by shale oil, OPEC, and other onshore
production. US shale oil production is ex-
pected to grow to 8 MMb/d by 2030 in our
base case. Yet barring a considerable price
increase, resource constraints in legacy plays
and high declines (another 1. 5 MMb/d of
production will need to be replaced by 2030)
will start restraining output beyond that level.
Global shale is not yet economic enough to
fill the gap. Similarly, OPEC output is likely
to be capped by the group’s policy of output
restraint and also affected by the region’s
lingering political instability.
In our base case, OPEC will grow produc-
tion only to maintain market share, with most
of the new growth coming from Iran and Iraq,
adding some 2. 5 MMb/d over current OPEC
production levels. Yet this is still not enough
to fill in the supply gap. The rest of onshore
production is expected to add 7. 2 MMb/d, in-
cluding production that needs to be replaced.
Consequently, over the next decade a gap
of 15-16 MMb/d will remain, resulting in a
market tightening that presents a considerable
opportunity for offshore and especially lower-cost deepwater greenfield projects.
Cost compression has made offshore projects increasingly competitive since the downturn, and the gains are expected to be partly
retained thanks to fundamental changes in the
way operators approach projects. Drivers of
reduced costs include greater standardization
and modular design, higher use of existing
facilities through tiebacks, as well as better
coordination between operators and suppliers.
Lower personnel costs and rig rates are also
expected to last for some time, and single
source service suppliers should help keep
The use of newer and more powerful rigs
further helps improve project economics, as
do more competitive fiscal terms from governments that seek to encourage faltering
development; a good example of favorable
government policy includes the most recent
UK Budget revision toward transferable tax
credits at the time of a field sale.
As a result of cost compression, deepwater
breakeven levels are likely to continue being
20-25% lower than 2014, despite a situation
where oil prices increase to $70/bbl in our
base case. The wider margin created by lower
costs should place deepwater investments
firmly at the left side of the global oil cost
curve, making these projects viable to close
the supply gap.
Incremental new deepwater production from
pre-FID projects could thus reach 10. 4 MMb/d
by 2030, which along with increased shallow
water will be sufficient to meet the estimated
15-16 MMb/d required to meet demand and
replace the declines in existing offshore fields.
In order to achieve this level of deepwater
growth, the industry would need to invest $654
billion in cumulative capex for unsanctioned
projects by 2030. While this capex will likely
be distributed among the world’s deepwater
basins, it is expected that a significant portion
will continue to be invested in projects in Brazil’s presalt (~25%) and the US Gulf of Mexico
(~15%), thanks to their favorable economic and
Even if only a conservative portion of this
investment potential materializes, the low oil
prices we have experienced over the past two
years could therefore trigger a new wave of
deepwater investment by 2030. •