-- Robert Campbell is a Reuters market analyst. The views expressed are his own. --
By Robert Campbell
NEW YORK, Nov 15 (Reuters) - U.S. natural gas producers can only dream of achieving the crude oil-linked prices companies elsewhere get for their output but a quiet beneficiary from the shale gas revolution is the U.S. refining sector.
For gas producers, the holy grail is GTL --gas-to-liquids-- either through enormously expensive plants that turn natural gas into ultra-clean diesel fuel or by gaining access to other gas markets where crude oil sets prices.
For now gas producers have to wait. But the gap between crude oil and natural gas prices in North America is encouraging petroleum refiners to back out oil from their systems wherever possible and substitute natural gas.
Although the volumes involved are tiny the trend is likely to continue, particularly as it offers a partial solution to the diesel problem --the need to boost diesel yields and cut gasoline output.
Independent refiner Valero has been the most forthcoming about its plans.
The company is building new plants at two refineries that will use natural gas instead of crude oil to generate hydrogen, which all refineries need to remove impurities like sulfur from fuels.
Traditionally hydrogen has been sourced from naphtha reformers that produce high-octane gasoline components but this is increasingly costly way of making hydrogen given the high price of crude oil.
Producing hydrogen with a steam reformer, a plant that uses water vapor to convert methane to hydrogen gas and carbon dioxide, cuts hydrogen costs by some two-thirds.
More importantly, though, is that by cutting the reliance on gasoline output to produce hydrogen the refinery gets a bit of flexibility to tackle the diesel problem.
The diesel problem, in short, is that demand for middle distillates is growing faster than demand for other oil products but refineries are unable to shift output to reflect this changed pattern.
To get more diesel refineries have to produce more gasoline, that is increasingly hard to sell at a profit. This in turn crimps diesel output until the cost of the fuel gets high enough to offset losses from additional gasoline sales.
Given that Atlantic basin refineries are generally set up to produce twice as much gasoline as they do diesel, the extent of the problem becomes clear.
By breaking the link between hydrogen output -- a critical component of diesel production -- and gasoline components, a refiner gains a bit of flexibility to boost diesel yields without making more gasoline.
This helps explain the rapid growth of third-party hydrogen supply systems, particularly on the Gulf Coast, where industrial gas producers like Air Products and Praxair operate networks of hydrogen plants linked by pipelines to refineries.
But backing crude oil out of the hydrogen production process will only help diesel output at the margin. Large changes in refinery yields will require huge investments.
Again, the case of Valero is instructive. At a cost of $3 billion, the company is building two hydrocrackers at Gulf Coast plants that will mainly produce diesel fuel.
By processing low-value fuels under great pressure in the presence of hydrogen gas, hydrocrackers yield excellent diesel components.
They also meet refiners highest ambition: volume expansion, a massive boost to profitability in an industry where feedstocks are priced by volume.
For instance, the units Valero is installing will yield up to 1.3 barrels of high value fuel for every barrel of feedstock processed.
Hydrocrackers, or other plants that shift refinery yields away from gasoline and towards diesel, are what will be needed to tackle the diesel problem.
But the high cost of these units is a major hurdle.
After all many refiners are still licking their wounds after the last bout of expansions in 2007-08 ended abruptly with huge financial losses.
But refiners may face little choice but to invest or die. The plants that are closing today are those most exposed to the diesel problem and least able to do anything about it.