Exporting Oil?

Jim Brown
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If you believe everything you hear in the news it would appear the export logjam for U.S. oil has broken. In reality it is just a crack in the dam.

U.S. companies will be allowed to export oil that has been "processed" and that means regular WTI crude is not eligible. The change in the definition of processed will allow condensates to be exported. Condensates are processed at the field to strip off the gas prior to shipping. Condensate is an ultra light oil, which has a high gas component and therefore explosive in nature. Condensate can be "processed" relatively cheaply using a distillation tower.

Pioneer Natural Resources (PXD) instigated the petition to allow condensates to be exported. They have already have distillation units and they anticipate exporting condensate from the Eagle Ford Shale. Distillation towers are relatively cheap and the process is simple.

The impact to the oil industry will be minimal. At best we are looking at 500,000 bpd and multiple factors will have to be taken into account. The condensate will have to be shipped to an export location, stored separately from regular WTI and accumulated for eventual export. Buyers will need to be found, which should not be hard.

Condensate or "gas condensate" is a mixture of hydrocarbon liquids that are present as gaseous components in raw natural gas. The liquid "condenses" out of the natural gas when the temperature is reduced to below the hydrocarbon dew point temperature.

Basically when heavy gas is brought to the surface the temperature change causes the liquids in the gas to "condense" at the surface. It is the equivalent of steam condensing on the mirror in your bathroom when you take a shower. The mirror is colder than the air coming out of the shower and the water in the air condenses on the mirror.

Underground temperatures can be several hundred degrees hotter than surface temperatures. When that hot gas arrives at the surface the temperature change causes the condensation. Not all gas has the liquid components. Most gas is "dry gas" and you don't get the condensate.

The key point I think everyone is missing is that the condensate is typically used to dilute heavier oil so that it flows more readily through the pipelines. If the condensate is somehow stripped out of the process and sent for export then moving heavier oil through the pipelines is going to be a challenge.

This diluted oil is easier to refine than the heavier oil. What may happen is a combination of export and consumption. Some condensate comes from locations where it would be costly to ship to the coast as a separate product. It will continue to be used as a dilutive agent. The biggest market for condensate exports would be Canada. It could be used to dilute the oil sands bitumen into a product that flows through the pipelines and be easier to refine.

However, EOG Resources said in 2013 that 70% of Eagle Ford production should be considered condensate. They backed up their claims with charts showing API quality and production from various wells. WTI has an API gravity of 39 and heavy crude like the Mexican Maya have a gravity of 20. The smaller the number the thicker the oil. The higher the number the thinner the oil. The generally accepted definition of the break between oil and condensate is 45.

The reason this is not widely reported is that condensate sells for significantly less than oil. Eagle Ford 60 API condensate averaged $17.50 per barrel below WTI in 2012. Therefore producers would rather sell it as oil than condensate. EOG produced a chart showing 7 out of 10 Eagle Ford producers were actually producing 100% condensate and no oil based on the API gravity. Based on volume EOG showed that 70% of Eagle Ford production was actually condensate.

In the EOG chart below they show the production from 10 companies and the API of their production. Clearly the majority of production is high up on the condensate curve and very little oil is being produced. (Charts are from October 2012 presentation)

EOG Charts

EOG Table

If EOG's numbers are correct and we have no reason to believe otherwise this may be a windfall for the railroads. The current production numbers for the Eagle Ford are closer to the 850,000 bpd range with 600,000 bpd condensate. Since Canada is the most likely buyer of condensate to blend with oil sands bitumen the best way to get it there is by rail. We have thousands of railcars headed south from Montana and North Dakota loaded with WTI. When they return north they are empty. If this works out the way I expect the railroads will begin hauling condensate north and WTI south. It will be a win-win for the railroads.

I don't see this as the prelude to crude exports in the U.S. since that would be a far more dangerous proposition. Prices would spike to Brent levels, typically about $10 more per barrel today. Do we really want to pay higher gasoline prices permanently?

Enterprise Product Partners announced on Tuesday they were building a 340,000 bpd pipeline from the Bakken to Cushing Oklahoma. They expect it to be operational by the end of 2016. It will traverse 1,200 miles and solve the oil shipping problem for some producers. Enterprise is currently focused on Texas and Oklahoma and the goal is to move farther north.

After last week's condensate announcement you can bet they are thinking about a condensate pipeline to the north.

Oil Inventories

Crude inventories rose +1.7 million barrels last week to 388.1 million. It was the first gain in four weeks. U.S. production was 8.45 mbpd and still below the 8.47 mbpd high set five weeks ago. Imports were 7.34 mbpd and right in line with the average.

Gasoline inventories rose +700,000 barrels and the fourth week of relatively small gains. Gasoline demand was 8.91 mbpd and just under the 9.0 mbpd average for the last 8 weeks.

Distillates rose +1.2 million barrels and the fourth weekly gain. However, distillate demand declined to a multi-month low of 3.65 mbpd. That suggests fewer miles by trucks and lighter passenger loads on airplanes.

Inventories at Cushing rose +400,000 barrels to 21.8 million and the second weekly gain. Apparently managers are not going to let inventories fall to the 20.0 million barrel operating threshold.

Refinery utilization rose slightly from 87.1% and a multi-month low to 88.5%. Utilization should be over 90% this time of year.

In the graphic below green represents a recent high and yellow a recent low.

Natural gas inventory rose +110 Bcf last week to 1,829 Bcf. Since inventories are so low it will take record injections for the next 20 weeks to return inventory levels to normal at 3,750 Bcf by winter. This is not going to happen.

With the fundamentals so strong for prices I am amazed by the decline over the last two weeks. I would have thought the mundane injection levels would spike the futures but apparently everyone is expecting a miracle.


The equity market stumbled through a tough week that normally loses about -2% historically. Instead the averaged ended the week with minor gains or minor losses. The S&P appears poised to capture a new high this week and the Nasdaq and Russell 2000 should see some follow on buying from the Russell index rebalance on Friday.

Bad news is apparently good news for the market but a string of earnings warnings in a very low volume week could disrupt that feeling.

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Jim Brown

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