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Analyst’s View to 2020

From a refiner’s perspective, a new downstream paradigm has emerged, analyst Paul Kuklinski writes in his latest report:

Demand growth is exceptional. U.S. refiners continue to operate at seasonal record levels. Global throughput will also be at a record level of 81.8 MMBD in 2Q18, 1.5 MMBD higher than last year. Attractive margins are expected to continue in 2018 and 2019, with capacity well balanced with demand. Product prices the rest of the year are expected to mirror modest anticipated changes in crude prices.

A tight global product market for high-end products is expected to continue for some years. After this year, global oil demand is set to expand by 6.9 MMBD over the following five years to reach 104.7 MMBD in 2023, growing 1.38 MMBD annually.

One fourth of the increase, 1.7 MMBD, will come from demand for petrochemical feedstocks: naptha derived from light crude oil and condensates, and ethane from natural gas liquids. The International Energy Agency (IEA) forecasts demand for naptha will rise by 495 MBD over the period, ethane demand will rise by 885 MBD. Over the next 20 years, the growth in demand for petrochemical feedstocks will be larger than the loss of oil demand from the growth of electric vehicles. (The IEA is an intergovernmental organization of 30 member-countries that works to ensure reliable, affordable, clean energy, its website states.)

Out to 2025, demand for gasoline is expected to grow around 0.5% per year, diesel 1.3%, and aviation fuels 1.5% annually. Demand for petrochemicals has been growing at a 4-6% rate since 2010. Premium lubricants are growing at a 4% rate because of higher specifications for new vehicles.

U.S. refiners expect product demand to outpace refinery capacity additions the next two to three years, keeping utilization high, with inventories reverting to historic norms after a period of oversupply and competition from imports. Apart from downtime for maintenance, operating rates in the 90-95% range for high complexity refineries are anticipated compared with marginal 85% rates in weak years in the past. U.S. gasoline, diesel, and jet exports have become a mainstay to operations as refiners pursue growth in Mexico and Latin America as well as Europe and Africa.

Planned refining capacity additions of 7.7 MMBD the next five years pose a risk to simple refineries which is expected to result in forced closures, particularly after the impact of IMO 2020. (The International Maritime Organization, or IMO, based in London, England, is a United Nations agency that regulates shipping. The IMO 2020 rule sets a global sulfur cap of 0.50% on marine fuel, effective Jan. 1, 2020.)

Venezuela is currently being forced to close three of its four large refineries which had been operating at rates under 30%. Their combined capacity of roughly 600 MBD is equivalent to 3% of total U.S. refining capacity. Over 70% of the plants’ operators and process engineers have left the country for higher salaries and a better quality of life. Venezuela has to import products.

Mexico’s state owned, simple, coastal refineries produce large quantities of heavy fuel oil and will likely be forced to cut runs or to close in coming years. Mexico’s oil production declined 9% last year, or 240 MBD, to 2.23 MMBD. Production in March was 1.84 MMBD, the lowest since1980.

U.S. refiners located on the Gulf Coast and East Coasts are globally competitive and exceptionally well positioned. They have a $1.25/B advantage over European refiners due to their access to plentiful, low-priced, U.S. natural gas supply from the Permian, Eagle Ford, and Marcellus/Utica shales, among others. U.S. gas supplies are not tied to oil prices and are largely disconnected from global oil and gas markets.

Roughly 60% of the benefit is in the form of lower cost refinery fuel and the balance in feedstock for products sold. With this advantage, many are focused on upgrading heavy fuel oil and other low-value products into distillates, petrochemicals, and lubes.

They have another advantage: access to rapidly growing supplies of light, sweet, WTI crude from the Permian Basin. WTI has a 62% product yield of higher value gasoline and distillate, and a relatively low 35% yield of heavy fuel, which sells at a discount to the crude itself. The Brent benchmark is also a light, sweet crude, but Brent production is mature and in decline. Bakken crude has characteristics similar to WTI.

The majority of the world’s oil reserves consists of medium or heavy sour crudes, which sell at a discount to WTI and Brent. Production of these crudes is expected to be relatively flat the next few years. Arab Medium and Iraqi Basrah crudes are much higher in sulfur than WTI and have a higher, 48% yield of heavy fuel. Mexican Maya, which is in decline, and other heavy sour crudes, typically have a relatively low 36% gasoline and distillate yield and a much higher, 63% yield of heavy fuel.

U.S. petrochemical producers are also advantaged at the low end of the ethylene cost curve because of their access to ethane feedstock from natural gas liquids. They are competitive with producers in the Middle East, with costs well under the cost of naptha and LPG, the main feedstock in Europe and Asia.

With these advantages, major refiners are looking at the IMO 2020 mandated change in bunker fuel specification to reduce the sulfur limit from 3.5% to 0.5% as an attractive opportunity.

Distillate prices in 2020 are expected to be much higher in response. Some expect the IMO mandate will add $7/B to the price of crude in 2020. Light-heavy crude price differentials will certainly widen to the relative benefit of U.S. producers and refiners.

Exxon for one, plans to upgrade 200 MBD of its 376 MBD heavy fuel oil production to higher-value distillate and lube basestock. Last year it installed a 50-MBD coker at Antwerp and a 40-MBD hydrofiner at Beaumont, Texas. This year it will start up a 43-MBD hydrocracker at Rotterdam. It is adding 400 MBD new capacity at its three Gulf Coast refineries, an increase of 28%. Its 2017 downstream return on capital employed after tax was a very attractive 25%. It expects to double downstream earnings by 2025. Shell is planning to reduce its refining capacity to lower breakeven margins while it grows ethylene capacity.

In March, the heavy fuel oil discount to WTI on the Gulf Coast widened to $10/B, from a 2017 average of $3.80/B, which provides added motivation to upgrade refineries to make more light products and distillates for the bunker and other markets and less heavy fuel oil.

Demand for marine scrubbers as an alternative in 2020 appears to be off to a slow start. The size of demand for low-sulfur LNG bunkers as an alternative will have more clarity sometime early next year. Non-compliance is an option in 2020 which some anticipate might be in the 5-30% range. Time will tell.

Given these early indications, the WTI crude oil price in 2020 is expected to be in the $65-70/B range. Growth in global demand will be met by continued rapid growth in supply from the Permian Basin and other U.S. and non-OPEC supplies.

With the success achieved with its production cut, OPEC and its ally Russia are likely to remain proactive to keep the market in balance. The principle risk is to the upside from a geopolitical disruption. In that regard, Iran and Venezuela will likely remain at the top of the watch list.

Libya and Nigeria, who may remain fragile, and Angola all produce light sweet crudes, low in sulfur, tied to Brent. They yield a high percent of gasoline and middle distillates.

Libya recently produced just over 1.0 MMBD, the highest since mid 2013. Its 2017 production was 821 MMBD. It produced 1.6 MMBD in 2011, before the start of its civil war and could do so again.

Nigeria’s March production was 1.70 MMBD, the highest in two years and 250 MBD more than a year ago as a result of a lull in militant attacks.

Angola production of 1.52 MMBD is mature and in decline. It produced 1.71 MMBD in 2016. Production will remain low until the start up of the deepwater Kaombo Field in 3Q18 with capacity of 230 MBD.

An added uncertainty, also with upside risk, is a significant potential decline in the world’s conventional oil production which is expected to emerge in 2020 and beyond. It needs to be offset by a significant increase in upstream spending, the sooner the better.

Conventional oil production of 82 MMBD accounts for over 80% of world oil supply. The annual decline in these mature fields is 3 MMBD which needs to be replaced before supply can meet growing demand.

Complex refinery margins are expected to remain attractive the next few years giving refiners every incentive to invest in projects to upgrade heavy fuels into more profitable light products. Heavy fuel supply will be reduced significantly.

It is not yet clear whether expanded low-sulfur diesel production will be sufficient to meet increased demand from IMO 2020.

Paul Kuklinski, founder of independent research firm Boston Energy Research, selects equity investments in the oil and gas sector for financial institutions. Kuklinski can be reached at bostonenergyresearch@msn.com.

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