Over the past few years, midstream companies have responded to the boom in crude oil and lease condensate production in the Eagle Ford and the Permian by developing significant new pipeline capacity to, as well as storage and dock facilities in, both Houston and Corpus Christi. Now, with production in the Eagle Ford off its high and growth in the Permian slowing, these same midstreamers (and producers, marketers, refiners, and exporters of condensate and other refined products) are taking stock, and assessing not only what new infrastructure might still be needed in this period of lowered expectation, but whether shifting more of their attention (and liquids) towards Corpus instead of Houston might be warranted. Today, we continue our look at Corpus Christi’s increasing role as a crude/condensate powerhouse.
Prior to 2012 the only U.S. produced crude delivered by pipeline to Houston area refineries came from offshore Gulf of Mexico or onshore Louisiana fields. The majority of supplies were imports delivered by waterborne tanker. But in just three short years between 2012 and 2015, roughly 2 MMb/d of crude pipeline capacity was built or repurposed to deliver surging light shale crude production and heavy crude from Canada into the Houston area. Refiners have adapted quickly to take advantage of new sources of supply. But with much of the newly minted infrastructure underutilized, midstream companies still need to improve pipeline connectivity and storage accessibility to overcome area logistical challenges. Today we review RBN’s latest Drill Down report on Houston crude infrastructure – released today -- and announce RBN’s new infrastructure database and mapping system, called MIDI.
The deluge of light (and super light) sweet crude from U.S. tight-oil plays like the Permian Basin, Bakken and Eagle Ford has had many effects, including a push by refiners to rework facilities designed for heavy-crude processing to handle an excess of lighter oils. Many of these projects are underway and expected online in the next two years. Today, we consider refinery infrastructure investments that might not pan out in a low crude price world.
Crude oil distribution to Houston area refineries is still being re-plumbed to reflect the ongoing transition to domestic supply. Although plenty of new pipelines provide access for new crude flows into Houston, logistic challenges arise from a crude quality mismatch with refinery configurations. The handling of condensate – whether lightly processed for export or refined in a splitter is also increasing infrastructure overhead. Today we look at new crude infrastructure challenges in the Houston area.
Over 400 Mb/d of Gulf Coast condensate splitter projects could be online by the end of 2016. These splitters will compete for condensate feedstock with local refineries in the Eagle Ford able to process 475 Mb/d of light crude and condensate. Another 700 Mb/d of stabilization capacity in the Eagle Ford could be used to process condensate for export. But with low crude prices stalling production growth, splitter economics could suffer if demand exceeds supply and condensate prices increase as a result. Today we conclude our update on Gulf Coast splitters.
Average margins for a Gulf Coast condensate splitter have been about $5/Bbl better in 2015 than they were in 2014 but are still about $4.75/Bbl worse than an equivalent Gulf Coast 3-2-1 crack spread. The economics of condensate splitters have also yet to be tested in an environment if – as could happen later this year – crude production begins to decline. Are condensate splitters a better investment than just exporting lightly processed condensate under relaxed export regulations? Two companies considering projects seem to have reached different conclusions recently. Today we continue our update on splitter projects with a look at economics.
Two years ago production of super light crude known as condensate in the South Texas Eagle Ford was surging. Most Gulf Coast refineries did not want to process this light material and it was discounted to regular crude. The discounts led to a number of project announcements to build stand-alone condensate splitters – a kind of simple refinery that would process it into refined products. During 2014 these projects were cast into doubt by the easing of condensate export restrictions that appeared to offer a less expensive solution to the condensate challenge. More recently the possibily of declining production could also threaten splitter economics. But splitters are still being built and coming online this year and next – with two new projects announced recently. Today we review current splitter projects in the light of market developments.
According to the Energy Information Administration (EIA), liquids production from the Utica shale in Ohio (identified as crude oil but more likely all lease condensate) has more than trebled since January 2014 from 19 Mb/d to a projected 64 Mb/d in May 2015. Regional production of plant condensate from natural gas processing has also increased with the build out of gas processing capacity in the Utica and nearby Marcellus plays and could reach 50 Mb/d by the end of 2015. Midstream companies have been busy developing infrastructure to get this condensate to market. Today we look at developing infrastructure and markets for Utica condensate.
We estimate October 2014 Eagle Ford condensate production at 690 Mb/d and have identified 450 Mb/d of stabilization capacity that meets Bureau of Industry and Security (BIS) standards to classify the processed output as OK for export. That should make it possible for an estimated 230 Mb/d of processed condensate to be exported from the Gulf Coast in 2015. All that is needed to open the floodgates are more transport routes to export docks. Today we describe current and future routes planned by Enterprise to get segregated processed condensate to market.
Kinder Morgan expect to commission the first 50 Mb/d of condensate splitter capacity at their Galena Park terminal in Houston during the next month. The capacity is leased to BP North America and will be supplied with condensate via Kinder’s Eagle Ford pipeline gathering network. Another 235 Mb/d of condensate splitter capacity could be online by 2017 – most of it in Corpus Christi. Meanwhile the jury is still out on whether it makes more sense for a producer to use a condensate splitter or to just process their condensate through a stabilizer with distillation. Either way the resulting products seem likely to end up in the export market. Today we detail the splitter plans.
Two years ago, the Double Eagle condensate pipeline from the western oil and rich gas windows of the South Texas Eagle Ford basin simply provided access to Corpus Christi. By early 2015, the Double Eagle will be linked to the Kinder Morgan crude and condensate pipeline to Houston. Together the two systems will offer shippers access to Corpus Christi, Houston, condensate splitter capacity and diluent pipelines to western Canada. Today we describe the growth of this multi-destination delivery system.
The condensate potential of the Utica shale play in northeast Ohio continues to be talked up by producers drilling for oil there. Natural gas output in the Utica is doing pretty well on its own of course – part of the Appalachian Tsunami of production that includes the Marcellus play. Condensate in the Utica is still considerably less exciting with production topping out at 25 Mb/d in 2013 but fifty percent higher now (37 Mb/d in August 2014 according to the Energy Information Administration - EIA) as more processing infrastructure releases production from completed wells. Today we ponder prospects for shipping Utica production overseas.
Just over a week ago (July 3rd) Reuters reported that Enterprise Product Partners (EPD) sold their first 400 MBbl export cargo of condensate to Japanese trader Mitsui. That export follows private letters from the Bureau of Industry and Security (BIS) to Enterprise and Pioneer that represent a change in the government’s interpretation of 40-year-old legislation banning the export of unprocessed crude and condensate from the US. The apparent relaxation of the rules could open up export opportunities for shale producers – especially in the wet gas / condensate window of the Eagle Ford in South Texas. Today in the first of a two part series we describe existing stabilizer capacity and export routes to market in the Eagle Ford.
The crude oil market was agog yesterday with a news story broken by the Wall Street Journal that the Department of Commerce Bureau of Industry and Security (BIS) had provided letters of ruling to Pioneer Natural Resources and Enterprise Products Partners that would allow these companies to export a limited amount of wellhead condensate starting in August. If these rulings are more than just trial balloons sent up by the BIS to test the waters then they contradict previously accepted requirements for processing condensate before it could be exported. Depending on the yet-to-emerge fine print, these rulings could have a significant impact on US condensate exports as well as revenue prospects for those companies that have committed to throughput capacity at currently planned condensate splitters along the Gulf Coast. Today we navigate the nuances of the story.
Growing Canadian production of oil sands bitumen requires diluent to blend it to pipeline flow specifications. The resulting demand for diluent exceeds local Canadian supply from plant condensate production (aka, natural gasoline) – leading to imports from the US of more than 150 Mb/d in 2013 – a figure expected to grow to 460 Mb/d by 2018. That expectation for future import growth is based on the assumption that Canadian condensate supplies would remain relatively flat at about 140 Mb/d. But could the developing Duvernay gas shale play in Western Alberta turn those estimates on their head? Today we investigate the consequences for US condensate demand.