Total net imports of petroleum for August, released by the Energy Information Administration late last week, were just over 8 million b/d, 8.074 million b/d to be precise. Since the decline in US import dependence became a trend in 2009, that's the second-lowest figure recorded. The lowest was in February of this year, at 7.929 million b/d, but if the per-day rate of February was extended out to a 31-day month, instead of a 28-day month, it would have exceeded the total number recorded in August.

So we can say that August had the lowest import dependence for the US since late 1995 in terms of actual barrels. But in that year the US was consuming anywhere between 17 to 18 million b/d. Now, it's more than 19.5 million b/d. So imports as a percentage of total US consumption in August was far less than 16 years ago.

As Jeff Mower of Platts took apart the numbers, he found a few things in his reporting:

--The US's net product exports were the highest since the EIA began reporting data in 1993. They were 914,000 b/d, a staggering jump from the 489,000 b/d recorded in July. To show just how much things have changed, the US in August 2010, just one year ago, was a net importer of products at 439,000 b/d.

--The US exported a record high 895,000 b/d of all distillates. The US "pipeline" into the European diesel market continues to grow, with exports of 146,000 b/d to the Netherlands, that country being the primary refining and storage hub for the continent. Of the almost 1 million b/d of distilate exports, ULSD was the biggest chunk, at 602,000 b/d.

--The US' net exports of finished gasoline were a record high 430,000 b/d, up from 84,000 b/d a year ago. But the US remains a net importer of gasoline blending components at 588,000 b/d.

The trends driving these changes have been widely discussed: Higher US crude output, reduced US demand for gasoline, diesel shortages in other parts of the world.

But the trend may not continue. The potential culprit in reversing this trend would be the threat to close three big US East Coast refineries becoming reality. At one, the ConocoPhillips Trainer facility near Philadelphia, crude processing has been halted for several weeks. ConocoPhillips has said it will shut the plant in six months' time if no buyer is found for the 185,000 b/d refinery.

Also near Philadelphia, Sunoco has said it is seeking buyers for its 330,000 b/d Philadelphia refinery and its 175,000 b/d Marcus Hook refinery, with both scheduled for closure by mid-2012 if buyers aren't found. There won't be a stay of execution by Sunoco; it's getting out of the refining business. So it will be somebody else, or nobody.

Assuming no change in demand, closures at any or all of the three means that the output from those plants that now meets mostly East Coast needs is going to need to be replaced by something. Of course, the closures also mean that those facilities will no longer be importing crude.  

One scenario: US Gulf Coast refineries simply divert some of their current exports up into the Northeast market through pipelines such as Colonial or Plantation, and don't simultaneously increase their refining rates to keep their export rates up. Does that impact import dependence? It's a question of balance: are the increased product imports of a quantity greater than the reduction in crude imports no longer going into shuttered East Coast refineries? That's not likely. More probably would be that product imports are of a quantity more precisely matching consumer demand, whereas you can't fine tune a refinery's output to meet that demand so exactly.

Another scenario: pipeline capacity constraints mean that the East Coast becomes even more dependent on product imports. Do the higher quantities of imported products exceed the amount of crude that had been imported previously? Again, we'd cite the statement above, about imports being more able to match consumer demand exactly, without needing to buy crude that turns into petroleum coke or residual fuel that doesn't easily have a home.  

But if the Gulf Coast refineries increase their operating rates to compensate for the lost East Coast operations, it's possible there would be little to no impact on US import dependence. There is enough idle capacity in PADD 3 to compensate for the lost East Coast output; according to the EIA, there's about 1.2 million b/d of idle capacity in that region, and the refining capacity at risk in the East Coast is just under 700,000 b/d. Those East Coast refineries, given poor margins, certainly aren't running close to capacity, and the total PADD 1 operating rate isn't even 70%. So Gulf Coast refineries could easily fill that gap...but will there be enough pipeline capacity to take all that new product to the East Coast? And would Gulf Coast refineries raise runs enough to compensate for all the lost output in PADD 1?  

This speculation could go on ad infinitum. So here's a suggestion: just watch for what happens. The net exports figure can be found in the top line of this chart. It always fluctuates, so it may take several months to determine if the continued erosion of the US East Coast refining sector will slow the remarkable--and completely unforeseen--trend of declining US import dependence.

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