Awareness and commitments to address climate change are advancing rapidly, and downstream companies need strategies to address the shifting landscape. The demand for transportation fuels will wane over the longer-term, or rapidly decline—depending on two variables: policy and technology innovation. Downstream investment and operating strategies must account for the fundamental shift in regulations and demand trends, but also the competitive pressure from emerging market supply where overinvestment in refining capacity may continue. Still, there are opportunities for companies able to pivot to a lower-carbon fuels world through biofuels integration, petrochemical expansions, and other avenues.

Refined product demand

Our research on energy transition in the oil sector is based on an end-use sector-wise view. This is driven by policymakers', regulators' and original equipment manufacturers' (OEMs) differing strategies for decarbonizing. The pace of deployment - and therefore the influence on demand -varies widely among end-use sectors, country markets, and the scenario considered. IHS Markit energy scenarios assumptions provide an established framework to consider the oil markets and downstream outlook.

Rivaly scenario

• Oil demand continues to grow through the early 2030s, but increasing rivalry with other energy sources, efficiency gains, emission standards, and urban policy slow oil demand growth in key markets - resulting in a peak in global oil demand in the latter half of the 2030s.
• Advances in battery cost reduction and energy density help propel electric vehicle (EV) sales in the light-duty sector - particularly expanding mobility services (e.g., ride hailing, car sharing) companies—and diesel truck fuel efficiency standards reduce on-road diesel demand. However, the scale, complexity, and inertia of the established road transportation system moderates the pace of change.
• Through the 2030s, increasing fuel economy and emission standards are a larger force in limiting oil-demand growth in transportation than the penetration of alternative vehicles.

Autonomy scenario

• The stunning pace of adoption by consumers of driverless electric cars (DECs)—with many owned and operated by new mobility services companies—leads to much weaker oil demand.
• DECs operated by mobility services companies offer lower costs for mobility to consumers who do not wish or cannot afford to buy a car. This also fuels strong policy action by many governments to restrict use and sale of oil-powered vehicles and increase fuel economy standards.
• Policies that support no internal combustion engines (ICEs)—referred to as NICEs—in favor of electric powertrains will affect both light-duty and commercial-duty vehicles that operate in metro areas. NICE policies are also referred to as zero-emission vehicle (ZEV) mandates.
• Autonomous long-haul trucking and electrification of city-based trucks limit diesel demand growth. Policy focus on aviation and shipping—combined with societal pressures—also influences demand in these growing transportation sectors.

A core belief in both scenarios is a shift from free carbon emissions to one where carbon (or carbon intensity of fuels) and operations bear a cost, either explicitly or indirectly through regulatory constraints.The combined impact of these changes in the Rivalry outlook results in refined product demand growing by 10 million barrels per day (MMb/d) from about 88 MMb/d currently to 98 MMb/d in 2040. In contrast, demand in Autonomy falls by a similar amount to 77 MMb/d by 2040. penetration of alternative vehicles.

Investment trends

The refining environment has remained reasonably well balanced since recovering from the 2009-2014 oversupply period following the global recession of 2008/09. Global utilization rates have hovered around 81% to 82% on an annual basis since 2015.

The industry has benefited from stronger demand increases that have outpaced net capacity additions. Over a six-year historical period (through end-2019), demand has increased by approximately 7 MMb/d. Over this same period, investment in new refining crude capacity was 8.5 MMb/d on a gross basis but was partially offset by approximately 4.5 MMb/d of closures—resulting in about 4 MMb/d of net crude unit capacity adds.

Asian (specifically Chinese) refiners have dominated investment in refining over this historical period (chosen to mirror the forecast six-year known project window). The Chinese refiners added approximately 2.5 MMb/d of crude capacity, accounting for two-thirds of global net crude capacity brought online and over half of reforming vacuum gas oil (VGO) and vacuum bottoms upgrading.

Looking forward, global crude distillation capacity is set to pass 100 MMb/d, not counting an additional 4 MMb/d of condensate splitter capacity. Based on our current project list, and a conservative estimate of capacity rationalization, it appears that refining utilization should remain reasonably firm over the coming six-year period—even when accounting for weaker demand of about 0.5 MMb/d this year due to the estimated COVIDS-19 impact.

Decisions, decisions

Refining companies are facing a complex set of choices. On one hand, new long-horizon investments are faced with the prospect of declining fuels demand and pressure to decarbonize remaining liquid fuels. In this view, can investments in traditional fuels capacity be justified?

On the other hand, substantial demand for liquid fuels—and therefore a refining industry—is probable for the foreseeable future. However, the structure of the refinery, its feedstock sources, and its success factors could be quite different as successful companies pivot to a low-carbon supply business.

Refining companies can take a defensive or proactive stance when it comes to addressing these pressures. A defensive stance might include focusing on plant reliability, lowering costs, buying emissions credits (as opposed to generating credits), and shifting product placement into lower regulated (export) markets. This strategy returns cash to shareholders in the near-term but might threaten viability longer-term.

Companies that opt for a proactive stance will invest in low-carbon strategies including biofuels, bio-integration, lower carbon intensity crude oils, and perhaps hydrogen. Carbon reduction will be a central goal toward profitable long-term returns. Much of the return on these investments depends on the value of carbon emissions credits, which are not without risk. For example, will regulatory programs capture Scope 2 emissions such that investments or contracts for renewable offsite power help lower the fuel life-cycle emissions?

Petrochemicals and petrochemical feedstocks

Our analysis indicates that increasing demand, slowing NGL supply growth, and peaking fuels demand will lead to a greater need for naphtha and other feedstocks from refining.

There will simply not be enough "by-product" naphtha and NGLs produced over the coming decades to meet petrochemical growth. The multitude of streams and options - including offgases, LPG, and other low value streams - are still not enough without shifting the fundamental yield of fuels towards petrochemicals directly or petrochemicals feedstocks. Measured on a yield of naphtha-to-crude run, global naphtha yields will need to increase from about 12% today to 19% by 2040.

Refining and petrochemicals plant integration is a well-established strategy by some downstream companies. More will be needed and the most interesting questions center around which technologies and segments of the refining market will make the investments.

• In China today, there are large, highly-integrated refining and petrochemical plants that are online or starting up. These large plants produce around 40% petrochemicals but use no novel technology. Instead, they employ a series of naphtha-producing hydrocrackers to produce large volumes of hydrocrackate that is fed to reformers for paraxylene production (and some light naphtha-to-steam cracking.) Given the capital required and "downgrade" of diesel to naphtha, does this configuration make sense anywhere outside of China?
• New crude-to-chemicals technology and configuration schemes are being researched with one such plant online in Singapore. These plants promise even higher petrochemicals yields of 50% to 75% in a world-scale refining size (400+ kb/d). These plants are most likely to be built as greenfield sites in the Middle East, India, or Eastern Asia and they require a substantial commitment.

Finally, new technologies are coming to the market that promise to increase the yield of petrochemicals from existing fuels refineries. Many of these are based on fluid catalytic cracking technology, a long-time workhorse of the modern refinery. There are a multitude of intermediate or semi-finished streams used to produce fuels today that could, with the right reconfiguration, be converted to petrochemicals - typically light olefins or BTX aromatics. A potential advantage of these more modest process unit investments is they may be suitable for large existing Western refiners as well as Asian and Middle Eastern refineries. Western refiners as well as Asian and Middle Eastern refineries.

Kurt Barrowis the Vice President for Oil Markets, Midstream & Downstream at IHS Markit.

Posted 17 April 2020

What are the Uncertainties Facing the Energy Transition in 2020?

This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.