Imagine there’s no export ban – no need to split the condensate

Sandy Fielden, RBN Energy

Recent rumors coming out of Washington DC suggest that changes to US regulations that severely limit exports of US crudes are being discussed with a view to changes – perhaps even repeal. One idea that keeps popping up is a change to allow the export of lighter hydrocarbons that have a high API Gravity (above 55 or some other number), classified by the US rules as crude, but known to the rest of the world as condensate. Allowing the export of such field condensates could alleviate an oversupply glut of these lighter hydrocarbons that US refineries are not best configured to process. Today we ponder the impact of an end to the prohibition of condensate exports.

As we have described in previous posts, condensates are light hydrocarbons containing a significant percentage of naphtha range material.  There is no universal standard for what defines a condensate, but some number between 50 and 55 degrees API gravity is typically used to differentiate condensates from light crude oil (see Fifty Shades of Condensate Which One Did You Mean?). US condensate is arbitrarily divided into two broad categories. The first is lease condensate produced at or near the wellhead when it condenses from natural gas at surface temperature and pressure. Some lease condensate is also produced at the wellhead in stabilizer units designed to remove more volatile hydrocarbons from crude. The second category is plant condensate, also known as natural gasoline, pentanes plus or C5+, that remains suspended in natural gas at the wellhead and is removed at a gas processing plant (see Like A Box of Chocolates – The Condensate Dilemma). Both categories of condensate are substantially similar in composition but the US Energy Information Administration (EIA) arbitrarily defines lease condensate as crude oil and plant condensate as an NGL (pentanes plus). Furthermore, Department of Commerce - Bureau of Industry and Security (BIS) regulations also define lease condensate as crude oil.  As such, lease condensate is included in BIS regulations introduced in the 1970’s to restrict the export of US crude oil except to Canada or in specific circumstances from Alaska and California (see I Fought the Law).  Thus lease condensate exports are prohibited even though plant condensate exports are perfectly legal.,

US lease condensate production is booming. Figure #1 below shows our estimate of current production (now above 1.2 MMb/d) and where it is being produced. You can see that the engines of condensate growth are the Eagle Ford and Permian basins in Texas and the Anadarko primarily in Oklahoma in areas like Granite Wash and SCOOP (South Central Oklahoma Oil Province).  But the big driver is Eagle Ford where we believe that up to 45 percent of crude production is more correctly categorized as condensate. We expect lease condensate production to increase to 1.6 MMb/d by the end of 2018.These numbers are only estimates because the EIA do not separate out crude and condensate production statistics in current production numbers and they may be even higher than we suggest because surging tight oil production from horizontal drilling in the Permian Basin is likely producing increasing volumes of condensate (see Stacked Deck).

Figure #1

 

Source: RBN Energy

While production of lease condensate is booming, the market for this very light hydrocarbon is rather limited. The obvious solution to the condensate market challenge is to process it like crude oil as a refinery feedstock. However that is hard to do because refiners have a low opinion of condensate, which is currently flooding the Gulf Coast market (see Don’t Let Your Crude Oils Grow Up to be Condensates). Part of the problem is quality – the wide variation in specifications like the API gravity of condensate and part is that most Gulf Coast refineries are not configured to process large quantities of very light crude because it can overwhelm their downstream upgrading capacity. As a result, lease condensate is a buyer’s market in the US at the moment – especially in the condensate rich Eagle Ford basin. Producers suffer unwanted discounts from refiners – of up to $20/Bbl at the Gulf Coast versus light sweet crude benchmark Louisiana Light Sweet (LLS).

In our view, the disposition and price impact of light crude surpluses are some of the most important issues in the crude oil and petroleum product markets today, and will continue to be for the next few years – regardless of what happens to BIS regulations. 

Another condensate market is feedstock for petrochemical crackers but that market has dried up in the US right now because of a shale boom led surge in ethane that is now far cheaper and more profitable to process as a petrochemical feedstock. One of the only markets with growing demand for condensate range material is diluent to dilute heavy Canadian bitumen crude so that it can flow in pipelines and some railcars. Some lease condensate makes it to Western Canada via the Capline and Enbridge Southern Lights pipelines (soon to be joined by the Kinder Morgan Cochin reversal), although most diluent is sourced from natural gasoline (plant condensate) barrels. In addition it looks as though local Western Canadian shale production in the Duvernay basin may meet more Canadian diluent demand with local condensate production in the future (see De Duvernay).

The export ban compounds the challenge of finding a market for lease condensate and has led to several US midstream companies making plans to build condensate splitters (see Whole Lotta Splittin’ Goin On). These stand-alone units are used to process condensate into its component fractions – mostly NGLs, naphtha and distillate or jet kerosene. Using a splitter allows a producer to transform lease condensate that cannot be exported into hydrocarbon products with no such restrictions –since they have been “processed” Processing is the litmus test in BIS regulations. Our analysis shows that 8 companies have announced plans to build condensate splitters in addition to the already operating 75 Mb/d Total/BASF unit at Port Arthur, TX. Some of these plans are further along than others – notably the Kinder Morgan 100 Mb/d splitter being built in the Houston Ship Channel – delayed earlier this year – but still due online in November 2014 with the first 50 Mb/d of production fully contracted to BP. Similarly on their way to completion are splitters (topping units) announced by Marathon at their OH and KY refineries. Magellan, Castleton and Martin Midstream have announced plans for three splitters at Corpus Christi on the Gulf Coast south of the Eagle Ford. In all, we estimate 495 Mb/d of condensate splitter capacity is currently being built or planned in the US – much of it apparently designed to circumvent the export ban.

Imagine There’s No Lease Condensate Export Ban

A recent spate of rumors and vague sounding statements from energy leadership in the Obama administration suggest that the Government may now be willing to change the crude export regulations.  On May 13th US Energy Secretary Ernest Moniz stated in a conference that "The nature of the oil we're producing may not be well-matched to our current refinery capacity” and that a change to regulations was being discussed.  Of course, “discussed” is a long way from “changed”, particularly in an election year.  But we hear that the notion of lifting the ban on condensate exports – maybe by reclassifying lease condensate as condensate instead of crude is being floated. If and when that rumor turns into a change in the rules, we imagined the consequences.

For one thing, US crude producers would likely be getting paid more for their condensate than they currently receive. As we have previously described, Gulf Coast refiners are imposing “bend-over” posting deducts to producers at the wellhead for condensate based on every 10th of a degree API over 45 (see Don’t Let Your Crude Oils Grow Up to be Condensates). At the Gulf Coast where most transactions occur, prices paid for condensate are being discounted by up to $20/Bbl over LLS. In other words, if you are selling lease condensate in Houston these days, expect to be stiffed. In stark contrast the price of condensate in overseas markets is much higher. Figure #2 below shows prices from Petroleum Argus for LLS crude over the past two years (red line) and prices for North West Shelf (NWS) condensate (blue line). The NWS condensate is produced in Australia and sold into Far East markets where there is strong demand for condensate for petrochemical and refinery feedstocks. Last week (16 May 2014) NWS prices averaged $107.45/Bbl - $3.73/Bbl more than LLS (103.72/Bbl). Since the beginning of 2012 the two prices have tracked quite closely, with LLS on average $3/Bbl higher than NWS. Even accounting for the freight cost of shipping condensate from the US Gulf to the Far East (perhaps $3/Bbl) Eagle Ford producers would be receiving a far better price for their condensate than they are currently getting at home if exports were permitted.

Figure #2

Source: Petroleum Argus

And there are a couple of other interesting ramifications to an end to the US lease condensate export ban to contemplate. (Apart that is from the furrowed brows we would expect to see at the condensate splitter project meetings the next day). One likely big change would be that Canadian heavy crude oil blended with diluent would suddenly become far easier to export via US ports. Just a couple of weeks back, Platts reported a cargo of Western Canadian Select crude sold to Repsol for export to Spain - loaded at Freeport, TX after an export license was obtained from the BIS. That cargo reportedly was shipped to Freeport by rail in order to ensure that none of the diluent used to blend it was actually US condensate (which could not be exported to Spain). If the lease condensate export ban is lifted, it would be far easier for Canadian producers to ship dilbit crude by pipeline to US ports without concern about diluent originating from the US getting blended in by mistake.

Another market to watch closely if the ban is ended would be US flagged Jones Act tanker and coastal barge freight. We have described the growth in that market previously as a good deal of surging US crude production has ended up traveling to market by water (see Rock the Boat). Much of that increased demand for freight has been to move condensate range material from Corpus Christi to other Gulf and East Coast Ports (see Float, Float on) – a trade that has seen volumes leaving Corpus jump from zero to over 400 Mb/d in the past three years. The result of that boom in movements out of Corpus has been record freight rates for tanker and barge owners. If condensate exports were allowed, we presume that a great deal of this trade would jump from the US registered Jones Act vessels that are required to ship condensate between US ports onto foreign flagged vessels headed overseas.

So as with all regulations, the desire for change in the rules by some parties will always leave other parties less than satisfied with the results. All of this is speculation at the moment of course, but we feel obligated to continue the theme in our next two episodes by imagining the impact of a complete end to crude export restrictions and the consequences for US refiners.

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