Theyre Tough to Beat

Its tough to beat the advantages held by U.S. and Canadian base oil producers, he stated at the ICIS Pan American Base Oils & Lubricants Conference in December. These structural advantages are inherent to the region and its resources. Mexico, with its one base oil plant in Salamanca, does not enjoy the same advantages, Ames added. However, U.S. lubricant demand is shrinking, so to exploit this advantage, the U.S. must export its barrels to expanding markets where lubricants demand is growing.

Among their blessings, operators of U.S. and Canadian refineries can count low-cost crude, natural gas and utilities, economies of scale, integration with their mother ship refineries, and locations that make exports easy.

Fourteen API Group I and II plants are operating in the United States and Canada (excluding rerefiners and those that process naphthenic base stocks), and Ames puts their combined nameplate capacity at 11 million metric tons per year, of which two-thirds is Group II. Thats important because Group II produced by hydrocracking is the lowest-cost process for manufacturing base oil – even lower than making Group III or Group I.

Refinery data from energy research firm Purvin & Gertz/IHS confirms this. According to the firms John Leavens, net production costs for Asias Group II producers are more than $100 per ton higher than U.S. Gulf Coast hydroprocessors.

Among the 14 U.S. and Canadian paraffinic suppliers, Ames counted six Group I-only plants, three hybrids that make both Group I and Group II, and five Group II-only plants. (Of the latter, Petro-Canada also makes some Group III, but its output is heavily weighted towards Group II.)

Looking more closely at the structural advantages these plants have, the most obvious one is access to abundant crude, Ames said, especially so-called tight oil crude from shale fracking, and tar sands crude from Canada. No major pipelines exist to move these crudes efficiently to the continents refineries, so drillers have resorted to 100-car rail shipments, with each tankcar holding 26,000 to 29,000 gallons. Transporting oil this way costs $12 per barrel, so any refiner who is located near the producing fields and can use the crude locally has a big advantage.

A glance at a map shows that many base oil refineries have such an advantage: The Marcellus and Utica fields are close to American Refining Group in Bradford, Pa., Ergon in Newell, W.Va., PBF Energy in Paulsboro, N.J., and Petro-Canada in Mississauga, Ontario; the Eagle Ford, Permian Basin and offshore Louisiana plays are within easy reach of U.S. Gulf Coast refineries; and the Western Canadian fields abut Imperial Oil in Strathcona, Alberta. And HollyFrontiers plant in Tulsa, Okla., is a stones throw from the Cushing terminus for West Texas Intermediate crude.

Are tight oil crudes good for making lubricants? Mostly yes, because all paraffinic crudes are good for making Group I and Group II, Ames explained. Certainly, West Texas Intermediate and West Texas Sour are good lube crudes. However, it must be said that tight oil is lower in density, and makes more naphthalenes and light products, while having less vacuum gas oil content. Hydro­processors tend to prefer waxier VGO because it helps to boost the viscosity index of the resulting base oil.

The low density and reduced VGO content of tight oil crudes may be a hindrance for smaller refineries – but its no problem for big Gulf Coast refineries, he added. They typically have multiple crude units and are designed to switch among crudes with ease.

The U.S. ban on the export of crude oil further traps crude within the countrys borders and depresses its value. With all this crude backing up and no ability to export, we have a glut thats even impacting crude that does not face pipeline limitations. Even Gulf Coast crude prices are lower now, too, Ames said. What we have is a feast of choices for U.S. refiners who can buy good crudes for far less than the North Sea Brent that underpins global crude pricing.

Whats this crude price differential worth? Ames pegs it at $1 per barrel of base oil produced, or about $7 per metric ton. More significantly, the landed cost of oil in the refinery is what really matters, he emphasized. Thats the logistical cost of getting the oil from the wellhead to the refinery, and its generally lower in the U.S. than the cost of freight from Europe. Today generally, U.S. and Canadian refiners have a $15 to $40 per barrel advantage, just in crude costs.

With increased shale fracking, U.S. and Canadian plants also are seeing lower natural gas prices, which slashes their utility costs. The cost last year for natural gas to fuel their energy-intensive processes ran about $4 per BTU, versus $9 in Europe and $15 in Asia.

Bountiful natural gas also makes it cheaper to generate hydrogen – and base oil plants eat a lot of hydrogen. A Group II lube plant equipped with hydrocracking, hydroisomerization and hydrofinishing units requires about 2,000 cubic feet of hydrogen per barrel of feedstock. This hydrogen comes from on-site steam methane reformers which use natural gas as both feed and fuel.

Today, U.S. refiners can make hydrogen for about one-third of the cost of Asian refiners, simply because of the cost of natural gas being so much lower, Ames said. And if even less hydrogen is needed – as in ExxonMobils proprietary Raffinate Hydroconversion process, which uses only one- to two-thirds as much hydrogen as a hydrocracker – the advantage grows, he added. Ames estimated that U.S. Group II hydrocracking refineries have an $80 to $100 lower cost [per ton of base oil] than Asian refineries, simply from this lower cost of hydrogen.

Finally, sheer scale benefits U.S. and Canadian refineries. Most of the regions Group II plants are huge, and some Group I plants are huge as well, said Ames. The average North American base oil plant is twice the size of those in Europe and Asia, and the average Group II plants are larger still. Operating at this scale allows fixed costs like labor, insurance and overhead to be spread over a larger number of tons produced. That can result in a $30 to $50 per ton advantage for Group I producers, Ames said, although for Group II producers it may be only a $10 to $20 per ton advantage over their average Asian competitor.

Many also reap integration benefits by being located alongside large fuel and chemical plants. Ames noted that all six USGC paraffinic base oil plants are housed at high-ranking mother ship refineries that average 430,000 barrels per day of crude capacity. Such giants typically have multiple crude and conversion units, configured to optimize feedstock for both base oils and fuels production.

Another example of integration: North Americas four largest Group I plants are located in refineries having delayed coking units and hydroprocessing capacity, which gives them a ready outlet for low-value byproducts. Some base oil refiners make too much DAE, which is dumped into fuel oil. Their asphaltenes also get dumped into lower-value streams. But if you have access to a hydro­cracker and delayed coking, you can upgrade those byproducts to fuel and get a higher value, Ames observed. The bottom line: Good integration can improve a Group I plants economics by as much as $30 to $60 per ton.

Logistics and location comprise the final advantages – especially for export-minded Group I and II refiners hugging the Gulf Coast. In the first half of 2014, about 45 percent of all U.S. base oil production was exported, Ames said. Mexico and Canada were the traditional export markets, and then Europe and South America, but now the even more distant markets of Africa, Middle East and India are the targets.

Whats it all worth in practical terms? Versus their European counterparts, Ames awards a cost advantage of $55 to $140 per ton to U.S. Group I plants. In the Group II arena, this edge grows to $125 to $170 per ton, versus Asian Group II producers. Of course, not all refiners may benefit to the same degree, he cautioned. Especially, the largest plants typically will enjoy the greatest cumulative cost benefits.

Adding up all the advantages, he declared, you cannot find a single European producer who can undercut U.S. production in Group I and II in their own home market, even when adding in the cost of the freight to land it.

Nothing lasts forever of course, and todays advantages could fade or totally evaporate. So here are some key indicators to watch, Ames said:

Lower crude prices could lead drillers to shut-in high-cost U.S. crude and Canadian tar sands, which would snug up the oversupply that benefits refiners.

OPEC members such as Saudi Arabia, Venezuela, Iran, Nigeria and Russia have national budgets that are highly dependent on crude oil revenue; they could act in concert to cut output, but that is not happening so far.

If the U.S. were to allow exports of crude oil, it would shift the balance of power from the refiners back to the producers. This is a politically sensitive issue which Ames believes wont be resolved until after the 2016 U.S. presidential election – if then. Meanwhile, the current glut of U.S. oil creates a buyers market.

If U.S. refineries reconfigure their crude units to process lighter crudes, it might affect feedstock availability for base oil units.

Will North American natural gas prices remain low? U.S. and Canada both aim to export liquefied natural gas next year, which could suck up the excess supply and push up domestic prices for natural gas.

So far, none of these indicators have budged. So although the magnitudes will vary, dont expect U.S. and Canadian base oil refiners advantage to disappear in the near term, Ames concluded. Yep, theyre tough to beat.