Like A Box of Chocolates – The Condensate Dilemma – Part 2 Demand

Supplies from the three main branches of the US condensate family are increasing faster than demand can keep up. Field condensate production from shale basins is nearing 1 MMb/d - headed to 1.6 MMb/d by 2018. Plant condensate – aka natural gasoline - will increase from just over 0.3 MMb/d in 2013 to more than 0.5 MMb/d in 2018. Because field condensates cannot be exported to overseas markets, more of this material will be refined traditionally or using a splitter – pushing out existing refinery demand for natural gasoline and creating an excess of naphtha range material. Petrochemical demand for natural gasoline has dried up in the face of cheap ethane feedstocks. Canadian demand for natural gasoline as diluent will soak up some but not the entire natural gasoline surplus. With US gasoline demand declining, the only outlet for excess naphtha and natural gasoline will be more exports (beyond Canada). Today we look at changing condensate demand patterns.

This is Part 2 of a two part series looking at the gap between surging condensate supplies and market demand. In Part 1 we provided definitions of the 3 branches of the condensate/pentane family and then detailed growing US condensate production. In this episode we tackle the demand side of the equation. Much of the material in this blog is adapted from a presentation Rusty made to the 3rd Annual Platts NGL Conference in Houston at the end of September (2013).

If you are new to condensates then you can refer to a number of previous RBN Energy posts on the topic in conjunction with this one. At the end of last year we provided some early definitions and looked at regulatory issues around condensates in our “Fifty Shades of Condensate” series including “Which One Did You Mean?”, “What Should be Done With Condensates?” and “Where is All This Condensate Going?” Earlier this year Al Troner of APPEC consulting contributed a couple of blogs on the market for condensates outside the US including some comprehensive definitions (see Through The Looking Glass). And there have been others on specific topics that (as usual) we will provide links to as we go along.

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Demand for Field Condensate

Field condensate is a buyer’s market in the US at the moment – especially in the condensate rich Eagle Ford basin – where up to 45 percent of crude is actually condensate. Producers suffer unwanted discounts from refiners that have a low opinion of their product, which is currently flooding the Gulf Coast market (see Don’t Let Your Crude Oils Grow Up to be Condensates). The Energy Information Administration (EIA) classifies condensate as crude, meaning that under Department of Commerce rules it cannot be exported overseas, where it might find a more welcoming home – for example in Asia (see Through the Looking Glass). Unlike the EIA, refiners do not consider condensate to be crude and they especially don’t like the box of chocolates problem – not knowing what they are getting. Refiners like standard, predicable crude grades that have qualities that do not vary much from batch to batch.  Crudes like West Texas Intermediate (WTI) and Light Louisiana Sweet (LLS) fit the bill.  Eagle Ford condensates are the opposite end of that spectrum.  Every condensate seems to be different and the quality varies over time.  The chart below is a scattershot of condensate assays, looking at only two qualities, API gravity (basically a measure of viscosity) and reid vapor pressure (RVP - a measure of volatility see Regulatory Gas Pressure Party).  Some Eagle Ford condensates get a lot lighter than this – well above 100 API and look more like y-grade (mixed) NGLs than they do condensates.  It is the wild west of U.S. hydrocarbons markets.

And not only is there a lot of variability from one condensate to the next, the other big  problem with condensates is that they contain too many light hydrocarbon components that refiners do not need. These light components can overwhelm refineries configured to process heavier and more stable crudes – reducing effective refinery throughput capacity.  At the moment this characteristic is constraining how much condensate Gulf Coast refineries can process – even though the price is routinely discounted by $20/Bbl against LLS.

Source: Turner Mason/RBN ENergy (Click to Enlarge)

Outside of conventional refineries there are few alternative homes for field condensates. It can and does get used as a diluent for Canadian heavy bitumen crude (see Heat It!). However, because of its unstable specification Canadian producers generally prefer to use natural gasoline that is produced to a standard quality. Shipments of condensate are making their way to Western Canada as diluent – via Houston (see It’s a Kinder Magic) or the Louisiana LOOP terminal (on the Capline pipeline). But the Canadian pipelines (today the Enbridge Southern Lights system, soon to be joined by the Kinder Morgan Cochin reversal) carrying diluent into the producing region in Alberta impose quality equalization standards that discount material that does not meet specification – meaning that some blending or pre-processing is required before field condensate is acceptable for diluent use.

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