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The future for global crude oil supply faces perhaps the widest
array of challenges and uncertainty since the mid-1980s. Factors
influencing the competitive supply of oil include: volume, quality,
and cost of supply of remaining resources; investment behavior; and
concerns about demand destruction or "peak oil" in a political
environment focused on promoting renewable technologies.
The drive to short cycle-time, unconventional projects onshore
in North America and elsewhere seemed irresistible for a large
swath of publicly traded companies. This focus accelerated after
the 2014 price drop albeit with a lag. The business proposition
rested on dramatic performance improvements, lower risk (both
actual and perceived), capital flexibility, and the transparency of
activity. It was also true that a great deal of conventional
activity was not making money prior to 2015, as upstream return on
capital employed (ROCE) fell progressively from 2010, even with
$100 oil prices.
Still, the exploration and production (E&P) business is
incredibly dynamic. Disenchantment with financial returns from
unconventional production onshore in North America is now reducing
investment there - even as larger operators determine different
development pathways that emphasize financial returns but with
lower growth. Investor questions may even drive more operators back
to conventional exploration in the medium term, or conversely,
drive investors out of the upstream sector altogether. Offshore
companies have been able to substantially reduce the costs of
building and operating the offshore facilities necessary to develop
resources in deeper waters. Global conventional development
drilling has picked up since 2015 but only slightly, remaining well
short of pre-2016 activity levels (see Figure 1).
Figure 1: Conventional NFW, appraisal, development versus US
horizontal wells
Offshore conventional new field wildcat (NFW) activity has
experienced only incremental gains at best, which will create a
knock-on effect on development drilling. From a global perspective,
conventional exploration and discoveries are at the lowest level in
seven decades. This is not due to lack of resource potential but
rather to investment behavior, enforced by the financial
sector.
Some larger E&P companies and a few E&P independents
continue to pursue selective deepwater exploration. For example,
ExxonMobil and its partners, Hess and China National Offshore Oil
Corporation, have been very successful in the western portion of
the Guyana Basin (offshore Guyana). Over six billion barrels of
oil-equivalent recoverable resources have been discovered in Guyana
since 2015, with the first volumes coming onstream at the very end
of 2019. Additional discoveries by Tullow Oil and its partners have
been made in more shallow water, but commerciality has not yet been
established. In an environment where operators are largely focused
on becoming cash flow-positive as soon as possible and financing
future development activity from within the existing cash flows,
these assets in Guyana represent an ideal package (see Figure
2).
Figure 2: Offshore Guyana Basin Investment Outlook
They offer globally competitive economics with break-even points
for the confirmed projects averaging around US$41 per barrel (bbl),
with a range between US$23/bbl and US$60/bbl. They also offer
shorter project cycle times than have existed in typical deepwater
developments, with the assets returning positive cashflows within
the first two to four years of production.
In short, there are E&P companies with engaging, financially
attractive portfolios, strategies, and performance to come. But how
many Guyana Basins or Johan Sverdrup's (in offshore Norway) are
there? There may be other new sizeable crude streams that are
highly competitive, with break-evens at $25 to $45 per bbl.
However, even if volumes are 300,000 to 500,000 bbls/ day, this
does not make up for overall industry trends. There are simply not
enough highly competitive investment opportunities for enough oil
and gas companies.
National oil companies face additional intense pressures and
obligations, but mostly it is a favored few (via natural endowments
and high capabilities) versus the many. Overall, the industry
remains more challenged than ever. Has the global competitive
landscape in E&P really changed, or is it the fact that the
financial sector has less patience with E&P against the
backdrop of the energy transition?
Consider the concerns about demand destruction or "peak oil" in
a political environment determined to promote renewable or green
technologies. Current concerns over global warming and the
resulting shift to renewables have led to some scenarios that show
a peak in oil demand as early as the 2020's; other scenarios show
oil demand peaking beyond 2030. Given this uncertainty, the
industry appears to fear over-investment rather than
under-investment. We see this in diminished conventional drilling;
slowdowns in unconventional drilling; seismic acquisition; new
acreage acquisition; and declining investment in improved oil
recovery/enhanced oil recovery projects.
Given these factors, IHS Markit predicts that the most
competitive barrels in the future will be those that offer the
lowest cost, lowest emission, and shortest cycle time (that is,
faster time from decision to cash flow), and flexibility of capital
commitment. Arguably the best short-cycle conventional resources
are in the Gulf countries as well as Western Russia. Others include
selected shallow water areas globally; subsea tiebacks in maturing
phase deepwater basins (where infrastructure rules); and
best-in-class new deepwater plays, whether in the Guyana Basin or
certain deepwater basins in Brazil. Other resource classes include
much lower but more profitable growth in onshore North America and
big, albeit long-term natural gas plays. These opportunities and
the required performance are not available to all or even many
companies, however.
Large basins can provide the scale and materiality to achieve
further cost reductions via improved performance, infrastructure
sharing, and fiscal regime change. But, smaller, higher-cost basins
may struggle to attract investment in a low-crude oil demand
scenario. Most governments will not easily accept declining
investment in domestic basins due the impacts on revenues,
employment, and national energy concerns. But how many governments
have the capacity to sustain E&P investment in less-competitive
basins for extended periods?
The E&P sector has more options than ever before from a
subsurface perspective. Yet collectively it faces unprecedented
challenges due to the uncertainties in future oil and gas demand
and investor concerns. The industry is unquestionably resourceful.
Since the oil price downturn in 2014, new approaches to project
design, applications of digital and other technologies,
efficiencies in the supply chain, and sharp focus on company
portfolios have combined to significantly reduce costs and create
"high quality" assets which can compete in the future, uncertain
business environment. For conventional offshore projects as
example, it is not uncommon to see break-even costs at some 60% of
the level that would have been achieved in 2014. Those companies
that continue to apply these approaches relentlessly will be in the
best position to appeal to investor sentiment within the financial
community. But, there may well be too few "quality," competitive
investment opportunities for the E&P industry as a whole; parts
of the industry will not able to attract investment capital. The
competitive landscape in global E&P will see further, deeply
significant changes. This future E&P industry will then be able
to take advantage of the inevitable opportunities that will emerge
as the global energy sector continues to evolve.
Jerry Kepes is head of the Strategy & Competition
Group, Upstream Research & Consulting Division at IHS
Energy. Siddhartha Sen is a Director of Energy Research &
Analysis at IHS Markit. Keith King is a senior advisor at IHS Markit.
