Blog November 27, 2019

Background

This is the third in a series of three blogs exploring the impact of IMO 2020 on international crude and distillate markets. The first in this series focused on U.S. distillate fundamentals, and the second took a closer look at what fuel substitution will mean for distillates, stock levels, and the ability of European refineries to supply low sulfur fuels. This installment will explore the potential impact an IMO 2020 world could have on crude markets and refinery runs.

This January, the International Maritime Organization (IMO) sulfur content regulation for fuel used in maritime vessels will decrease from the current 3.5 percent to the newly-regulated 0.5 percent. One solution to meet the new regulations is to switch from traditional bunker fuel to cleaner burning fuel, such as Marine Gasoil (MGO) or Ultra Low Sulfur Diesel (ULSD). Thus, demand for cleaner finished products will increase, incentivizing refineries to optimize both crude slates and refinery units.

In addition to the changing regulatory environment, the supply of heavy crude oil is declining, creating a secondary market impact. In the spring of 2019, this supply shift caused the price spread between light crude and heavy crude to narrow and briefly reverse with heavy trading at a premium to lighter crude grades. As IMO 2020 approaches and demand for light crude increases, this light vs. heavy price spread widened.

In our final blog in this series, we will address both environments: IMO 2020 and the changing availability of crude. The new IMO 2020 regulations are forcing refiners to produce cleaner refined products from distillates to residual fuel oil. For non-complex refineries (refineries without a coking unit), this is increasing the appetite for light sweet crude oil. Complex refiners will continue to source heavy crude, especially as the premium of light vs. heavy crude increases. Some refineries are optimizing their ability to meet market conditions by investing in new secondary units, such as additional hydrotreating capacity and coking units. The key to weathering uncertainty in 2020 is the flexibility to run economical crude grades while producing cleaner refined products to meet market demand.

Changing Crude Slate

Global heavy crude availability decreased significantly over the year. Supply in key oil-producing regions waned amid Venezuelan and Iranian sanctions, Canadian curtailments, and Mexican legacy declines. Our Global Supply Oil Report and Global High Frequency Monitor observed these steady declines, especially in the first half of 2019.

U.S. Heavy Crude Oil Imports by Region
Figure 1: U.S. heavy crude oil imports by region. Source: EIA company level imports

These production declines, along with several geopolitical factors, such as the Saudi refinery attacks at Abqaiq and previously mentioned drop in key producing regions, narrowed the pricing differentials between heavy and light crude grades. Waterborne heavy sour crudes remained tightly supplied. These differentials were indicated by several key spreads, including Brent vs. Maya and Brent-Dubai.

The Brent vs. Dubai price spread is a key indicator of this heavy crude oil shortage. Brent crude represents the global benchmark for light sweet crude, while Dubai represents the benchmark for heavy sour grades. Historically, the North Sea blend (Brent) traded at a $2-4/bbl premium to Dubai, but in February 2019, we saw the differential reverse with Brent trading at a discount to Dubai. In 2018, the monthly spot price differential for Brent vs. Dubai averaged $2.11/bbl. In 2019, the annual monthly spot price differential decreased by 65 percent, falling to an average of $0.75/bbl through December.

Brent vs. Dubai Light Heavy Spot Price Differentials
Figure 2: Brent vs. Dubai light heavy spot price differentials. Source: CME

In the U.S. Gulf Coast, another heavy to light grade indicator is the Brent vs. Maya price differential. In April 2019, the differential narrowed significantly and then inverted. In 2018, the monthly spot price differential for Brent vs. Maya averaged $9.85/bbl. In 2019, the annual monthly spot price differential decreased 35 percent, falling to an average of $6.42/bbl through December. In both cases, the light vs. heavy spread began to widen towards the second half of the year. Demand for light, sweet crudes steadily increased with IMO 2020 fast approaching.

Brent vs. Maya Light Heavy Spot Price Differentials
Figure 3: Brent vs. Maya light heavy spot price differentials. Source: CME

Non-complex refiners are incentivized to run light, sweet crudes to meet the upcoming sulfur specification change, which played a part in widening the heavy/sour vs. light/sweet spreads.

“And as you would expect, as high sulfur fuel oil has traded weaker we’re starting to see that in the crude quality discounts. So through most of the year, we’ve had heavy sour trading inside of a 10 discount to Brent. It’s almost 20% discount to Brent today, Maya and WCS. I think Maya [is] trading at 11.50 discount to Brent today. And we’re seeing medium sours that get weaker as well. So I think on the feedstock side of the business, it’s pretty clear…”

- Valero Q3-2019 earnings statement on October 24, 2019

Refinery Complexity

Starting January 1, 2020, complex refineries will have an advantage over low conversion refineries, with the ability to upgrade heavy crudes to produce lower-sulfur products such as distillate, marine fuel, and residual fuel oil. Complex refineries are often tied to the Nelson Complexity Index (NCI). High NCI refineries have the ability to transform crude to a variety of refined products. Secondary units, specifically coking units, are desired to convert bottom of the barrel feeds by splitting longer-chained molecules into shorter chains, thereby maximizing output of more valuable fuels and products.

To meet the new regulations, non-complex refiners will demand more light, sweet grades, and these crude grades will likely become more expensive in the short term. Building coking units would be beneficial in the long run, allowing refiners to process cheaper, heavier crudes. Refiners without heavier processing units at their facilities stand to have margins reduced after diluting fuel output into lower-sulfur products and creating significant product waste running less-complex units alone. This waste might occur if non-complex refineries do not have the capability to convert bottom of the barrel grades, thus decreasing yield. Coking capacity adds both competitive advantage and increased flexibility of crude slate in the IMO 2020 environment.

Nelson Complexity Index by region. The solid bar represents the median NCI followed by 25% quartiles.
Figure 4: Nelson complexity index by region. The solid bar represents the median NCI followed by 25 percent quartiles. Source: Genscape

Refineries in North America, specifically in the U.S. Gulf Coast region, have higher NCI ranges. Boasting a median NCI of 9.79, the Gulf Coast region is the most complex refining center in the world. Europe is second with a median NCI of 7.87, followed by Asia with a 7.47 NCI. However, NCI values do not represent the entire refinery diagram. Other secondary units such as hydrotreaters, and hydrocrackers offer refineries the ability to produce additional distillate and meet the expected increase in demand.

Percent of selected refinery units by region
Figure 5: Percent of selected refinery units by region. Source: Genscape

U.S. Mid-Continent and Gulf Coast regions have the most cokers in total at 50 percent. European refineries have fewer cokers, at just 13 percent and 14 percent, respectively. Another demand center, Asia Pacific, has cokers at 42 percent of refineries.

“…the clean/dirty spread using Asia gas oil and high sulfur fuel oil…is expanding with the forward curve and third-party estimate ranges showing further widening, which will favor more complex refiners with the capacity to upgrade heavier sour crudes to cleaner products.”

- ExxonMobil Q3 2019 earnings call on November 1, 2019

High conversion refineries are better positioned to capitalize on market changes and the availability of variable quality feedstocks while optimizing crude slates based on economics.

Solution: Construction Projects

Since the announcement of IMO 2020, refinery construction projects increased. The new projects consist of atmospheric distillation towers, coking, and other downstream unit construction. More complex refining capacity is coming online in Europe, Asia, and the Middle East, which should produce more clean products such as diesel and less dirty products such as fuel oil. Europe has additional investments, such as ExxonMobil’s recent announcement to invest more than $1 billion to expand their 270,000 bpd Fawley, United Kingdom, refinery. This investment will increase production of Ultra Low Sulfur Diesel (ULSD) by 38,000 bpd with new hydrotreater and hydrogen plants, according to a company statement.

However, no other region is expanding as rapidly as the U.S. Gulf Coast. These projects position refineries for both the changing crude supply and changing regulations. Led by ExxonMobil’s 250,000 bpd 2021 expansion project at their 369,000 bpd Beaumont, TX, refinery, we expect substantial North American capacity to come online in the next few years. To meet the short term needs of IMO 2020, there are several new coking unit projects coming online, such as Marathon’s new 40,000 bpd coking unit at their 585,000 bpd Galveston Bay, TX, refinery and PBF Energy’s recommissioning of the idled 12,000 bpd coking unit at their 189,000 bpd Chalmette, LA, refinery.

Operator Site Unit Added Capacity (bpd) Date in Service
Delek Krotz Springs ALKY 6,000 Q2 2019
Exxon Baton Rouge Coker 20,000 01 Jan 25
  Baytown Coker 20,000 01 Jan 25
    FCC 10,000 Q1 2019
  Beaumont CDU 250,000 01 Jan 21
Marathon Galveston Bay CDU 40,000 01 Jan 22
    Coker 40,000 01 Jan 20
  Garyville Coker 75,000 Q1 2020
PBF Energy Chalmette Coker 12,000 Q4 2019
Phillips 66 Lake Charles ISOM 25,000 Q3 2019
  Sweeney FCC N/A Q2 2020
Valero Houston ALKY 13,000 Q2 2020
  Port Arthur Coker 55,000 01 Jan 22
  St. Charles ALKY 17,000 Q2 2020

Figure 6: Gulf Coast construction projects and expansions. Source: Genscape

These capital-intensive expansions are in response to both the changing crude slate and new global regulations. One thing is for certain in this changing environment: refineries are optimizing their ability to meet new market conditions by giving themselves greater flexibility to run economical assays and produce cleaner refined products.

2020 Refinery Demand Outlook

Winter months typically bring strong distillate margins in North America. In 2019, these margins were offset somewhat by weaker seasonal gasoline margins. Recently, refining margins strengthened as refiners are optimistic about IMO 2020 specification changes for bunker fuels boosting distillate demand. In 2020, we expect U.S. refinery crude demand to increase 473,000 bpd relative to 2018. Seasonality is further boosting margins, with summer driving season over, the switch to higher Reed Vapor Pressure (RVP), lighter, winter-grade gasoline happened in October.

North America Refinery Demand
Figure 7: North America refinery demand. Source: Genscape

Potential Risk: Refiners Specialty Fuels

In the short term, one potential risk is running specialty fuel grades that are compatible with tanker engines. Several majors offered their own specialty fuels following several months of testing bunker fuel blends, and tankers may find that specific blends work better in their ships. Moreover, blending of distillate fuel with residual fuel oil for bunker use has its challenges, as increased volumes of distillate used to lower sulfur content could lead to viscosity or compatibility issues with the end-use product. This could be a considerable advantage to major refiners, and a considerable disadvantage to small, independent refiners. For example, major refiners have the synergies to create and offer the same blended fuel oil at main shipping hubs. Tankers might be keen on only using a certain fuel, rather than mixing fuels or buying a generic blend.

“So the investments we're making and have made, certainly Antwerp, Rotterdam are good examples, the Singapore resid upgrade project that I mentioned earlier, all of those are intended to capture the growth in that demand and improve the complexity of our refineries and the competitiveness of those refineries. We are absolutely investing to capture that long-term demand growth.”

- ExxonMobil Q3 2019 earnings call on November 1, 2019

Conclusion

In 2019, heavy crude oil supply decreased significantly, briefly reversing the light/heavy spread this spring. Since then, the light/heavy spread steadily widened with the anticipation that IMO 2020 will increase demand for light, sweet barrels. If this demand persists into next year, complex refiners will be advantaged to slate heavier and cheaper barrels.

In the short term, demand for light, sweet crudes should remain high globally, as less-complex refineries source barrels to meet product specifications. In the long run, construction projects, especially coking units, will help balance the crude oil market and optimize their ability to meet market conditions and supply constraints.

We’re going more in depth about the possible IMO 2020 impacts on the market during our live webinar on Tuesday, December 3 at 3:00pm ET. Register now to join the conversation!