Plains All American Pipeline LP chief executive Greg L. Armstrong shed some light on crude oil market fluctuations at the recent IPAA luncheon on January 11, 2012. In particular, Armstrong notes that petroleum consumption in the U.S. has fallen off rather significantly, over the last three or four years, since the recession. This trend, he opines, has ultimately led to price differentials in regional markets, such as the WTI and Brent crude differential.

“Because we’ve seen oil consumption go down and other sources of production go up, we’ve seen a decline in refined products imports on a net basis, and we’ve also seen a decline in imports of crude oil. So, crude oil imports are down about 1 million barrel (MMbbl.) per day, and refined products imports, amazingly enough, we’re now a net exporter of refined products in the U.S.,” explains Armstrong.

In fact, in 2005 the U.S. imported 3.6 MMbbl. a day of refined products, and exported 1 MMbbl. per day of refined product, and thus were a net importer of 2.6 MMbbl. a day.

“Lo and behold, six years later, we have decreased our imports from 3.6 MMbbl. a day to 2.7 MMbbl. per day, and increased our exports from 1 MMbbl. to 2.8 MMbbl. a day. So for 2011, we expect to import a net 100,000 bbl a day. So that gives you a total swing in the trade balances of 2.7 MMbbl., just in refined products. If you combine that with 1 MMbbl a day decreasing crude oil, we’ve actually decreased our reliance on foreign petroleum 3.7 MMbbl a day during that time period,” he says.

Concerning this shift in focus on drilling in the U.S., the emphasis has clearly moved from gas-oriented drilling to crude oil-focused drilling. The areas that are most active in this focus are the Rockies, West Texas and the Eagle Ford.

As a result of that, for the first time in a long time, the market has seen an uptick in production, of several hundred thousand barrels a day in the Lower 48 onshore. When one combines that uptick in production with an increase in ethanol production, it becomes apparent that U.S. producers have increased domestic supply by about 1.2 MMbbl. per day.

“So, contrast this increase in crude oil production with the record increase we’ve had in natural gas production. Clearly, the increase in natural gas production had a severe detrimental impact on gas prices. So I’ll just pose the question, will that increase in crude oil production have the same impact? I don’t think so. But it can and likely will have an impact on quality and regional differentials, which is what we have seen,” says Armstrong.

There’s a prevailing perception that domestic light sweet crude will simply back out waterborne foreign imports. “We import about 6.5 MMbbl. per day of waterborne crude to the U.S. So with increasing production, whether it’s coming out of Cushing, out of a pipeline, or whether it’s coming out of the Eagle Ford, over toward Houston, or on a barge through Corpus Christi, at the end of the day there needs to be a market for that product to be able to take it anywhere, which becomes tricky with these issues,” says Armstrong.

Many refiners have spent a lot of money to process heavier, sour crude. So the reality is that the vast majority of foreign imports that come into the Gulf of Mexico are already sour or heavy barrels. Ultimately, the prices for this light sweet crude have to be adjusted to displace those heavier sour barrels.

“You may have refiners running 300,000 bbl. a day and they’ve got 200,000 bbl. a day slated for heavy sour crude. If you want to force another 100,000 bbl a day of light sweet crude, they are going to have to change the refining process to be able to handle that. So they are going to charge for that. You would think light sweet crude should get the highest price, when in reality in a regional market you may find out that it actually gets a lower price than heavy crude,” says Armstrong.

Moreover, about 10% of the 5.3 MMbbl. per day of product that comes in to the Gulf Coast is light sweet crude.

“If you increase that to include light sweet and the medium grade, that number gets up to about 25% of that, so you are about 1.1 MMbbl. per day ultimately, from what is available. Again, there is not an easy solution for this product and ultimately a lot of this light sweet crude coming to market is going to have to be discounted, or the refiners are going to have to make major changes,” he says.

In October 2011, the differential got out to roughly about $25 to $26 per bbl. between WTI and Brent. Armstrong explains, “Basically, depending on where your production was located, you could be $25 discounted. There were several events that also caused this WTI-Brent differential.

Between the Fall of 2010 and the Spring of 2011, Cushing inventories increased about 25%. They went from 32 MMbbl. to roughly 40 MMbbl. and that started to cause some congestion, and people started storing more and more crude. Around that same time, the unrest in Tunesia and Egypt started, which added a lot of tension. Also, we hit peak inventory at Cushing in April of 2011 at 41.9 MMbbl.”

In addition, political and social unrest rolled across into North Africa, and into Libya, which caused the price of Brent to skyrocket. Once the differential hit $10, commodity funds started to follow crude oil and commodities in general.

“The stock market was not appealing at that point in time, and so a lot of money went into commodities, and particularly into crude oil. In particular, the Brent and WTI profile changed. However, once Gaddafi was shot, that started a decline in the differential because Libya production, which is a substitute for Brent, was going to be coming back on the market,” he says.

Ultimately, Armstrong predicts that this differential will remain ever-present for regional markets throughout 2012.

“I think the price of crude oil will be very volatile but robust, and the regional differentials will increase and decrease in fits and starts. These differentials are going to continue challenge conventional wisdom,” he cautions.