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Kemp: Rising stocks reflect overpriced US crude

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U.S. crude stocks held by refiners, traders and pipeline companies have hit the highest level since the Great Depression, as refiners hold out for cheaper prices before they take in more domestic oil.

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Stocks rose 3.5 million barrels last week to almost 398 million barrels, according to the latest data from the Energy Information Administration. It is the highest volume of crude in commercial storage since weekly records began in 1982.

Based on monthly records, it is probably the highest since 1931, when the country was in the midst of the depression and crude was gushing from the newly opened East Texas field.

Record stocks have been piling up on the Gulf Coast, home to the country’s biggest refineries. But “with parts of the refinery system continuing to require heavy and sour foreign crudes, insufficient volumes of imports are being displaced by indigenous supplies to prevent stocks building,” BNP Paribas analysts wrote.

Crude inventories normally build at this time of year as refineries take advantage of the lull in demand between the winter heating season and summer driving season to take some units offline for planned maintenance.

Stocks have risen by 37 million barrels since the end of December, which is fairly typical. But inventories ended 2013 at an unusually high level, so even an average stock build has been enough to push them to an 83-year high.

Inventories usually continue rising until late May or early June, when refineries ramp up throughput to maximize gasoline production after the start of the driving season on Memorial Day.

Past experience suggests stocks could build by another 5-10 million barrels, topping 400 million barrels in the coming weeks.

Beneath the relentless rise in U.S. oil stocks is a disconnect between the type of oil that the United States is producing and the type that U.S. refineries want to process.

Refineries use linear programming to tell them which crudes to purchase, based on their configuration as well as the current slate of dozens of different crude and product prices.

The resulting computer models contain thousands of equations, which help them determine the most profitable crudes to process.

U.S. crude, especially the light crude being produced from shales such as Eagle Ford in Texas and Bakken in North Dakota, typically costs more than the heavier crudes still being imported from Canada, Mexico and Saudi Arabia, and produces a less valuable mix of products.

Light oil cannot be exported (except to Canada) because of the longstanding ban on crude exports, so it must be processed internally or put into storage.

U.S. refiners could process more domestic crude, but most prefer to continue processing heavier imported oils as well, because it is more profitable.

Shale oils are mostly light. On distillation, they yield a high proportion of light fractions suitable for making gasoline. The yield of medium and heavy distillates useful for diesel and heating oil is far smaller.

Traditionally, gasoline has been the premium fuel in the United States, but U.S. refineries can now earn more from exporting distillates.

So the big Gulf Coast refineries have been redesigned to run on heavier crudes, cracking and coking them to produce more distillates.

Gulf refineries want to buy cheap distillate-rich crudes and crack them to produce lots of premium-priced diesel — not expensive light crudes and process them into lower-priced gasoline.

To some extent, refineries can cure the problem by processing a blend of light domestic oils and heavy imported crudes.

But that means there is a limit to how much light domestic oil the refineries want to use, and they need to continue importing heavier oils.

To clear the emerging glut, refineries will have to be given an incentive to run light domestic oil, which means it must become cheaper relative to imported grades of both light and heavier oil.

Kemp is a London-based market and energy industry analyst for Reuters.

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