Volatility is particularly difficult for base oil and lubricants makers, said Serra-Holm, since base oil prices dont reliably follow raw material costs. Unlike fuels producers, base oil refiners have no hedging instruments available to absorb the shock of crude price swings.

The resulting high level of margin volatility has been especially difficult for API Group I producers in Europe, she pointed out during the February meeting. While Group III producers deal with less margin volatility, their premium over Group I oils is slowly decreasing in the region.

In the United States, lubricant demand produces a disconnect between base oil prices and crude prices. Rates for Group I and Group II oils in the country closely track each other.

Asia is the region where Group III has managed to resist the pressure downwards, observed Serra-Holm. On the other hand, Group II prices there have dropped even lower than Brent crude. The price for Group III has fallen, but to a much less significant extent, she explained.

Because Group II margins in Asia have historically been so slim, some market players wonder whether there will be competition between gas oil and Group II base oils at refineries in the region. There has even been a period where gas oil had a higher price than Group II, Serra-Holm related, speculating that volatile crude prices may encourage refiners to refocus on fuels over base oil for better profitability.

In contrast to paraffinics, naphthenic crudes have a fairly stable outlook, said Serra-Holm, whose company produces naphthenic oils. Accounting for about 5 percent of the worlds crude reserves and 9 percent of base oil capacity, naphthenic fields exist worldwide but most production comes from Venezuela. Fields in North America and the North Sea are also sources of this crude, while plentiful reserves in China are used locally.

The industry may see an increase in production of nonconventional base stocks that are not tied to crude, she said, including renewable alternatives. The quality of biobased products in many cases is now at least equal to mineral base oils, and lube blenders are willing to pay a premium because of the impact on corporate image. The market share of biolubes has been holding steady at 1 to 2 percent globally, and Serra-Holm sees a potential boost from the use of biobased oils in nontactical ground vehicles in the U.S. military.

She does not believe that relatively low crude prices will impact the markets focus on sustainability. While lower oil prices have corresponded to an increase in the number of miles driven in the U.S., the fuel efficiency of new cars continues to rise there and in other leading markets such as France and Germany. Regulatory efforts, consumer perception and corporate image will continue to push sustainability goals, keeping up the pressure on lubricant producers to improve product performance.

High volatility in profit margins makes investment decisions difficult, and the fluctuating price of crude will be a major challenge for base oil refiners and lube blenders in the year ahead, Serra-Holm predicted.

Industry consultant Stephen B. Ames pointed out during his presentation that the drop in crude oil prices since 2014 has constrained the capital budgets of most integrated oil companies. Consequently, 27 base oil projects with total capacity of over 6 million metric tons per year have been postponed indefinitely or canceled in the past three years, and Ames expects about 6 million t/y of capacity to close over the next five years. Capacity that has been added recently came mostly from independent producers in China.

However, the difference-the 10 million ton net increase [over the past decade] against little or no increase in overall demand for lubricants and hence base oils-has led to a very unbalanced market today, which Ames estimates as a 5 million t/y surplus. Only recent closures and average capacity utilization of about 70 percent have turned the giant wave at the bottom of the log flume into a smaller splash-at least for now.

Including Group IV polyalphaolefins, naphthenics and smaller projects, Ames predicts another 5 million t/y of capacity additions by the end of 2021. The backlog of new projects has narrowed quite a bit as demand slowed and overcapacity became apparent, he explained. Four million t/y of paraffinic capacity additions are still on the global carousel, but none are certain, and none are expected to alight in North America, South America or Africa.

Group II is the biggest base oil category by volume in Asia and North America. Ames expects API Group I capacity to continue its swift decline, displaced by Group II, which is more cost-effective to produce. According to Ian Moncrieff of Kline & Co., who also presented in London, nearly 60 percent of new capacity added from 2000 to 2015 was Group II/II+, substantially outweighing Group I and naphthenic capacity closures. He pointed out that Group II plants cross over the negative cash margin at 10 percent lower capacity utilization than Group I plants, and foresees the addition of a total of 300,000 barrels per day (about 15 million t/y) of Group II and Group III capacity this decade (2010-2020), while another 130,000 b/d (6.8 million t/y) of Group I is retired.

Ames expects some of the surplus Group II in the U.S. to be shifted to Group III, tracking the declining use of Group II and II+ light neutral grades and meeting rising demand for light-viscosity passenger car motor oil.

With no change foreseen in overall lubricant demand over the next five years, no additional capacity can be added without closures or further reductions in capacity utilization, stated Ames. However, the return to a more balanced market will be slowed by national oil companies reluctance to close despite market pressures. Moncrieff pointed out that national oil companies owned a controlling interest in a third of the 1.1 million b/d of total global capacity in 2015, and nearly half of Group I capacity.

Moncrieffs presentation showed that Aramco, the Saudi national oil company, was the largest net seller of base oils in 2015 at about 2.2 million tons. The company will have grown its net supply capability by more than 1 million tons by the end of 2017 through its acquisition of Shells half-portion of Motiva in Port Arthur, Texas, and a 70 percent interest in Luberef, which is expanding its plant in Yanbu, Saudi Arabia. SK and ExxonMobil are the second and third-largest sellers.

Since 2000, five of what Moncrieff called supermajors have reduced their equity positions in installed capacity, while the interests of independents and others have doubled. These supermajors are rationalizing underperforming assets, he explained, in order to fight declining financial performance. Shell has been the most active in this realm, reducing nameplate capacity by roughly 4 million t/y since 2000. The producer has replaced less than half of that capacity with its Pearl and Hyundai Oilbank joint venture projects.

Other changes are also taking the industry for a ride. The idea that you have to supply from your own indigenous area refineries is a thing of the past, said Ames. Instead, large, advantaged base oil plants are the most competitive global suppliers. An advantaged plant, he explained, is part of a healthy refinery, uses hydroprocessing that provides greater feedstock flexibility and lower operating expenses, and has access to cost-effective marine transport. Such refineries can also secure low-cost crude as well as natural gas, for lower energy costs and lower hydrogen costs for hydroprocessing.

Ames lists 12 advantaged refineries, with combined capacity that accounts for more than 40 percent of global demand: ExxonMobils plants in Baytown, Texas, and Baton Rouge, Louisiana; Motivas plant in Port Arthur; Excel Paralubes in Westlake, Louisiana; Chevron in Pascagoula, Mississippi; SK, GS Caltex and S-Oil in South Korea; ExxonMobils Jurong, Singapore, plant; the Neste/Bapco plant in Bahrain; Adnoc in Ruwais, U.A.E.; and Shell-Qatar Petroleum in Ras Laffan, Qatar. The five plants on the U.S. Gulf Coast are among the worlds lowest-cost Group I and Group II producers, he pointed out. The Middle Eastern plants produce the lowest-cost Group III, with the Korean plants close behind.

Base oil plants are also affected by overall refinery economics, Ames reminded attendees. In the long term, low crude prices will only enable the most profitable projects to stay in the park. Unprofitable refineries will continue to lock the turnstiles, especially those dependent upon high sulfur fuel oil, which Ames expects will be heavily affected by the International Maritime Organizations revised MARPOL Annex VI marine fuel sulfur restrictions beginning in 2020.

Many Group I plants are part of older refineries in the third and fourth quartile of their peer group, in terms of profitability. Some have shut down because the entire refinery shut its gates, such as Shells plant in Montreal, while other refineries closed their Group I base oil plants to enhance overall refinery viability, as in the case of Essar Stanlow in the U.K. Still, Ames says, existing Group I plants are increasingly becoming unbalanced as they cant place their light neutrals. The Group I plants that do survive, he said, will focus on more-profitable heavy viscosity grades that have low cost and easy feedstock availability.

Moncrieff predicts a decline in global Group I capacity to about 296,000 b/d by 2030, down from 508,000 b/d in 2015. About two-thirds of that reduction will come from the closure of parent refineries; the rest will be base oil plant closures within the larger refineries.

In the long term, Moncrieff posits that Group I refining will drop to roughly the scale of the naphthenics industry, with a similar ownership model of mostly small- to medium-size independents and national oil companies. Group II and Group III will continue to see growth, while rerefining-currently 5 percent of total capacity-will capture more market share, especially in the case of high oil prices.