Fifty Shades of Condensates – Where is All This Condensate Going?

The surging production of condensate, or ultra-light crude oil, from America’s new shale-oil plays presents an opportunity that’s only just beginning to be recognized by much of the hydrocarbon market.  Historically U.S. condensates have been a tiny sliver of that market, usually blended into crude. Now there is just too much of the stuff, particularly in places that aren’t yet ready to process it in large quantities. In this next installment of Fifty Shades of Condensates we explore the constrained domestic demand for “raw” condensates at U.S. Gulf refineries and petrochemical plants, and the promising international outlets for condensate in Canada and Asia. Bottom line: unless the unlikely happens and the U.S. lifts restrictions on exporting “raw” condensate, producers, traders and other players will either be selling it here at a discount, or spending money to transform it to buy a little optionality. It’s all about spending the least they can to access pockets of demand, and first movers are already enjoying an advantage.

 [If you are new to condensates and you have not read the first three episodes in this series then reviewing them first will help, particularly Part 2 that covers definitions. Here are the links to Part 1 and Part 3.]

Yet condensates, an ultra-light, volatile hydrocarbon mixture, are quite different from the crudes that feed most U.S. refineries, and they don’t yield the same mix of products in the refining process. Condensates generally have an API “gravity” of 45 to 75 degrees. By contrast, the NYMEX benchmark West Texas Intermediate (WTI) crude has an API gravity of 39.  Motor gasoline has an API gravity in the low 50’s.  So much of this stuff is lighter than the gasoline you use in your car. 

RBN contributor Brandon Bello with Texon (see Wasted Away in Butane Blendingville) recently provided a picture that demonstrates the wide range of API gravities and what that means for the color of the condensate (see below).  The clear condensates on the left are the lightest.  Off the picture to the right are condensates as black as any crude oil.  See where we get the title ‘Fifty Shades’?

And as we’ve mentioned before, U.S. refiners – thinking a few years ago that most of the growth in crude supplies would be heavy crude oil from Canada have recently retooled to favor the processing of those much heavier imported crudes.  That’s exactly the opposite of what has ended up happening with the largest growth in crude volumes coming from light sweet shale crudes and condensates.

Unfortunately for the analyst of crude markets, the recent emergence of condensates as a major player on the hydrocarbon market stage has moved faster than the availability of data on condensates as a separate product.  Condensates are buried inside Energy Information Administration (EIA) statistics for crude oil, impossible to find in most state data (with Texas being a notable exception to that fact), and are generally not reported separately by producers in their financial statements and investor presentations.

Word on the street, corroborated by our friends at energy consultant Muse, Stancil is that as much as 50 percent of some producers’ Eagle Ford “crude” production is turning out to be condensate. Kinder Morgan, who signed BHP/Petrohawk as its anchor customer for its Eagle Ford crude and condensate pipeline, told us that “100%” of what it transports on its pipeline out of Eagle Ford is currently condensate, defined by Kinder Morgan as material over 50 degrees API.

The breakdown between crude and condensate is highly relevant, because prices of the two can diverge significantly.   A few weeks back RBN showed in a blog series on Eagle Ford crude that purchasers are discounting condensate prices by more than $15/Bbl (see Knocking on Heaven’s Door Part 1).  This was substantiated in a recent presentation by Muse Stancil, where Susan Starr showed that Eagle Ford condensate with API gravity of 60.1 was selling this past July for about $15 a barrel less than Eagle Ford crude oil with API gravity of 42.5.

To track this differential, Platts has launched a new Eagle Ford Marker to track a pool of Eagle Ford crudes (47 API) that prices $5 barrel lower than Light Louisiana Sweet crude.  RBN explored this index and the theory behind it in Clash of the Titans.

No one in the prolific Eagle Ford Shale is likely to be complaining about this surge of condensate production. Producers get to classify all this output under the catchall “crude and condensate” category that satisfies investors looking for exposure to $85-90/bbl crude prices.

So where is all this condensate going?

And where will it go as this early trickle grows into a river?   In the U.S. there are two main end markets for raw condensate: refineries and petrochemical plants. Both markets are problematic.

Many refineries are only configured to handle small volumes of condensates – what refiners call “light fractions”.  The sheer volume of new condensate and light crude coming on stream will cause these refiners a variety of problems.  We can summarize these problems into three general categories.

First, refineries are designed to handle certain mixes of crude oils with some equipment handling the lighter fractions while other equipment handles the heavier ends (See Sandy Fielden’s Complex Refining 101).   Put in a crude oil mix that has way too much of the light fractions, and the refiner’s equipment for handling that material gets maxed out.  And as that happens, the refiner’s equipment for handling the heavier ends can become underutilized.  A refiner can adjust to run the lighter crude mix – by cutting back on total capacity.  It works, but it’s a costly way to fix the problem because expensive refining capacity is underutilized.  Ultimately the only way to fix the problem is to invest in new processing equipment.

Second, condensates and light crudes have much lower yields of distillates (diesel, jet fuel) and much higher yields of naphthas (motor gasoline and similar products).  This is a problem for refiners because gasoline prices are much cheaper than diesel prices and refiners are making big margins on distillate-derived products and less money on gasoline.  So the lighter the input crude mix, the lower the margin.  RBN talked about this in Turner Mason and the Goblet of Light & Heavy.   

Third, a number of complex refiners are just completing major upgrades planned years ago to run more heavy crudes.  Essentially this makes problem #1 above worse for the refineries that went this direction. They have the ability to run more heavies just when the supply of lights and condensates is increasing.

For all of these reasons, the refinery system is starting to choke on light crudes and is responding with the one way to make the economics work out – reducing the price they will pay for condensates.  That $15 dollar differential mentioned earlier could get larger in the coming months.  So if larger volumes of condensates continue to go to refineries they will do so at a lower price.

The second, much smaller market for U.S. condensates is the petrochemical sector.  Petrochemical plants use condensate as a feedstock to create naphthas, which are then converted to other products used in plastics and a host of other materials. While different types of plants use different processes, all can start with raw condensate. But here’s the problem: As we discussed in Let’s Get Crackin – Part V: Natural Gasoline, a naphtha/natural gasoline feedstock is one of the most expensive and has been losing market share to ethane and propane feeds. What little condensate petrochemical plants still need is  coming from the Eagle Ford plays. This has already backed out a lot of international waterborne imports (like Algerian condensate) not leaving much additional demand for domestic condensate.

That said, from talking to industry participants it is clear that complex refineries are already processing far more condensates now than just a year ago. Why? The price is right. Plus, the rash of new pipeline projects already underway to carry Eagle Ford crude and condensate to refining centers in Corpus Christi and Houston virtually “guarantees that Eagle Ford crude and condensate production will find potential buyers on the US Gulf Coast,” Platts asserted in a recent report.  As we saw last week in Oh-Ho-Ho its Magic, light sweet crude imports could be backed out of the Gulf Coast by condensates and light domestic shale crudes sometime in 2013!  We expect refiners to bow to the inevitable and dust off old equipment or build new facilities to process condensates.

But producers hate fire sales for their products… so where else will they look for markets?

There are two main potential export markets for condensates: Canadian oil-sands operations use condensate as “diluent” to thin out bitumen oil and ready it for transport on pipelines. And petrochemical plants in Asia and Europe use condensate-derived feedstocks because in those markets natural gas is still scarce and expensive, driving up the price of light NGL feedstocks like ethane and propane.

Let’s turn to Canada first.  Diluent demand statistics are a bright spot for players in the Eagle Ford. (See Knocking on Heaven’s Door).   We dug into some Canadian regulatory filings and found this December 2011 Wood MacKenzie report, prepared for the Alberta Department of Energy, examining pipeline needs for Canadian oil exports as well as return imports of diluent. Figure 11 is on page 15 of this public report.  Note that although the graph is labeled Condensate Supply, it includes some cousins of raw condensate, such as a natural gasoline, also used to satisfy diluent demand.

Source: Wood MacKenzie, filed with Alberta Department of Energy

First, the obvious: the upward slope shows that diluent supply must grow to adequately dilute all the bitumen oil coming to market (excluding the volumes going to upgraders). The blue shows that Canadian diluent supply is flat to declining, and the report explains that this makes condensate relatively expensive in Canada. The gray area is the growing supply of diluent from Enbridge’s Southern Lights pipeline. The purple represents additional projected demand for diluent beyond what Southern Lights can deliver, that will come from rail and probably the reversal of the Cochin pipeline, a Kinder Morgan project that would bring more diluent material to Alberta. The 180 Mb/d Southern Lights pipeline runs from Chicago to Edmonton. Eagle Ford condensate is already being shipped from the Gulf Coast up to Illinois on various routes to join the Southern Lights pipeline.

While U.S. condensates are moving into the Canadian diluent market today, there is another huge global market for condensates: Asia. Condensates are used for refinery and petrochemical naphtha range feedstocks in both Asia and Europe. For the most part however the European condensate/naphtha market is well supplied and does not need more barrels from the U.S. The Asian petrochemical sector by contrast is heavily dependent on Middle Eastern supplies and eager to find new sources of raw material. We talked with Gulf Coast traders who are scouting opportunities to send naphtha derived from U.S. condensates to Asia. The reason?  It is generally believed that Asian condensate demand should double by 2016 (see this link to a Reuters report from August).

One reason condensate demand is doubling is that Asian refiners are building condensate splitters of their own to capitalize on a flood of Middle Eastern condensate that can increase both naphtha and gasoline output, according to research from Al Troner of Asia-Pacific Energy Consulting. This means many Asian buyers prefer the raw stuff (which can’t currently be exported from the U.S.), and naphtha from U.S. splitters could be more expensive than Asian naphtha once you pay the transportation cost for shipping it there on a tanker.

The conclusion many in the U.S. are drawing about the condensate chess game is that the most important thing to have is options. While there are risks to big capital investments, breaking condensates into usable and exportable parts in condensate splitters (basically just simple refinery crude oil distillation towers) could be a highly attractive solution.

One company that has the deep pockets to provide this optionality is midstream behemoth Kinder Morgan. Kinder announced in late 2011 that it would build a condensate-splitter and related storage units on the Houston ship channel. Oil major BP has contracted for most of the initial capacity of 50 Mb/d and is leasing storage. Kinder Morgan says the project is expandable to 100 Mb/d.

Kinder has said that the $200 million project, for the fraction of a cost of a refinery, will create all kinds of optionality as condensate swamps Gulf refineries. According to Don Lindley, VP of product development for Kinder's products pipeline group, “You chop it up into naphthas and middle distillates and bottoms material,” he says. “The naphthas have markets like refinery intermediate feedstocks, potentially gasoline blending, and certainly diluent. You can take that to several places. The middle distillates again can fit in as refinery intermediates, they can potentially fit into distillate blending, and that would include jet-fuel blending as well as diesel blending. And the heavier materials are just a better fit into the refinery generally as well and can also be used as heavier fuels like bunker fuels.”

Building a new splitter only makes sense; Kinder’s Mr. Lindley says, in a location with the right inbound pipelines, water access for exports, proximity to refineries, and an anchor customer who has firm commitments to deliver products processed from condensate. This could be why we haven’t yet heard of other new splitter projects. Another large refiner told us that getting environmental and emissions permits for new projects is challenging.

But look around, and you’ll learn of opportunistic moves to dust off existing distillation equipment in the Eagle Ford. Blue Dolphin Energy Co. is running 10 Mb/d at its small Nixon refinery in the Eagle Ford. Blue Dolphin has said it is exploring restarting another idled refinery nearby, built in the 1970’s, that also has “condensate processing equipment” but has only operated intermittently since then.

One risk with these projects is that the Commerce Department might relax rules on the export of raw condensate, and/or change the definition of what it means to process it. However, our best guess is that, with President Obama’s reelection, it’s going to be a long time before Washington hands the energy industry such a controversial gift.

In the meantime, buying optionality seems to be the best way to profit from this new onslaught of ultra-light crude oil.

Ann Davis Vaughan is the founder and president of Reservoir Research Partners, an independent research firm in Houston that provides highly customized, in-depth intelligence to institutional investors on public and private companies and markets. Prior to founding Reservoir in 2010, she spent two decades as an award-winning investigative and financial journalist, including nearly 14 years at The Wall Street Journal under the longtime byline "Ann Davis."  She covered commodity markets and the energy industry from 2006 to 2010.

DISCLAIMER: Reservoir Research Partners is not an investment adviser, nor is it affiliated with any investment adviser.