Whole Lotta Splittin’ Going On – Gulf Coast Condensate Splitter Economics

Midstream companies are building or planning 400 Mb/d of new condensate splitter capacity to process Eagle Ford production by 2016. BASF/Total have been operating a 75 Mb/d splitter at Port Arthur since 2000. The new splitters are being built in response to a flood of condensate range material coming out of the Eagle Ford into Houston and Corpus Christi. So what’s the big deal with condensate splitters? Today we look at splitter economics.

This blog is a follow up to our latest RBN Drill Down report titled Like a Box of Chocolates – The Condensate Dilemma which examines major developments in the world of condensates for the past few years and looks forward through 2018.  The analysis begins with an overview of the condensate family, including field condensate, natural gasoline and naphtha.   The remainder of the report then reviews (a) field condensate production forecast by major basin, (b) the supply/demand balance for natural gasoline, (c) Gulf Coast condensate splitter infrastructure and projects, and (d) a special spotlight on Utica condensate supply and infrastructure development.  More information on this report is available here.   Drill Down reports are part of the RBN Backstage Pass premium services package.


For those of you that have not yet signed up for RBN Backstage Pass, today’s post continues our blog series on infrastructure being developed to process and transport increasing volumes of condensate. We started that series by describing how refiner Marathon Petroleum (MPC) plans to handle more light condensate in their refineries in Canton, OH and Catlettsburg, KY and to construct condensate splitters at both facilities that will process 60 Mb/d between them (see Whole Lotta Splittin’ Going On). Then we turned our focus to similar plans to construct condensate splitters and specialized processing capacity to handle very light crude at Gulf Coast refineries and terminals (see Processing Gulf Coast Condensate). This time we look at the economics of operating condensate splitters.

We start with a recap on condensates for those new to the topic – skip this paragraph if you are an old hand. Condensates are light hydrocarbons containing a significant percentage of naphtha range materials.  There is no universal standard for what defines a condensate, but 50 degrees API gravity is typically used to differentiate condensates from light crude oil (see Fifty Shades of Condensate Which One Did You Mean?). Field condensate, also called lease condensate is produced at or near the wellhead, typically from stabilizer units.  Plant condensates, more commonly known as natural gasoline, are part of the NGL stream from natural gas processing plants and produced from fractionation facilities as a ‘purity’ NGL product (a.k.a., pentanes plus or C5) - (see Like A Box of Chocolates – The Condensate Dilemma).

Increasing volumes of condensate production not only in the South Texas Eagle Ford basin but in the Utica in Ohio and the West Texas Permian Basin are hard for existing refineries to handle especially in the Gulf Coast. That is because condensates contain too many light naphtha range materials that can overwhelm most Gulf Coast refineries that are designed to process heavier crudes. To get around this constraint several US refiners – most notably Valero and Marathon Petroleum Company are building new refinery units designed to pre-process condensates to produce feedstocks for gasoline blending and for upgrading units that produce diesel and jet kerosene. These refinery condensate processes are variously called topping units or splitters but they are operated as part of the overall refinery configuration and used to increase the output of finished refined products.

Condensate splitters by contrast are stand-alone basic distillation units – operated outside of a big refinery - and that characteristic helps define the economics of their operation. The idea of condensate splitters is not new and as we said earlier, BASF/Total has been operating one in Port Arthur since 2000. But now with at least four new stand-alone condensate splitters being built and planned in Corpus Christi and Houston, midstream companies are clearly looking to profit from processing the glut of condensate range materials building up at the Gulf Coast. And for those midstream companies condensate splitters represent an investment of about $200 million compared to the billions it costs to build a new refinery. The question is can these condensate splitters operate economically without the benefit of integration into a refinery?

One big factor in favor of condensate splitter economics is the low cost of purchasing condensate compared to regular crude oil. That discount - which producers have to swallow when selling their condensate is primarily caused by two factors. The first we just mentioned – namely that US refineries are not typically configured to process condensate range materials so demand is low even as supplies are surging – putting downward pressure on prices. The second factor is the US ban on exports of field condensates (see The Lease Condensate Export Problem) that effectively restricts the market for condensates to the US and Canada. As we have described previously, Canadian heavy crude producers generally prefer to use natural gasoline as diluent to dilute their crude to flow in pipelines (see Like A Box of Chocolates Part 2) so although there is some demand for field condensate in Canada it is not enough to soak up the US surplus. The net result is that in the absence of robust demand, US field condensate can be discounted by as much as $15-20/Bbl versus “traditional” light sweet crudes such as Gulf Coast benchmark Light Louisiana Sweet (LLS). So condensate splitters have access to plenty of cheap feedstock supplies.

The next step in our analysis of splitter economics is to determine what comes out the other end of a condensate splitter. A major impediment to that process is figuring out the hydrocarbon characteristics of the condensate feedstock – that of course determine the output. The evidence suggests that condensate quality in US shale formations is all over the board, making it difficult to identify a typical grade. Given all the investment in condensate splitters it is understandably hard to find public data about US condensate because operators are tight lipped. For this analysis we found condensate assay data for a well know Middle East condensate stream from the massive North Field in Qatar. Assay data tells us the hydrocarbon components that will be produced by simple distillation or splitting the condensate. North Field Qatar condensate has an API gravity of 58 and a sulfur content of 0.24 percent. Since US condensate gravities generally range between 50 and 70 API – with very low sulfur, the North Field assay should provide a useful model for our analysis. The table below shows the assay data. The left hand column lists the output components that are produced by running North Field through a condensate splitter.

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