New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017. With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.
The Colonial System is the largest refined products pipeline in the U.S. and delivers as much as 2.7 MMb/d from Gulf Coast refineries to destinations up the East Coast as far as New York. The southern section of the pipeline has been running full for over three years – leading Colonial to apportion space to shippers. A desire to gain shipper support to expand the pipeline led Colonial to propose new tariff clauses limiting trading practices that have developed around apportionment such as the sale of shipper history. Earlier this month (December 3, 2015) the Federal Energy Regulatory Commission (FERC) postponed the latest Colonial tariff proposal pending a user conference to resolve differences between the pipeline and shippers on these issues. Today we explain the oddities of line space and shipper history trading.
Refiners operating in the Permian Basin enjoyed healthy margins over the past four years as takeaway pipeline congestion discounted the price of local crude compared to market centers at Cushing, OK or the Gulf Coast. Although that trend reversed for a few months this summer when a shortage of crude at Midland caused prices to spike higher, the market is once again favoring local purchasers. As a result, refiners have invested in infrastructure to increase deliveries of local crude to their refineries as well as leveraging their gathering pipelines to double as takeaway routes for producers shipping outside the basin. Today we continue our review of Permian infrastructure build out.
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.
This Wednesday (September 30, 2015) PBF Energy announced their acquisition of the 155 Mb/d ExxonMobil Torrance, CA refinery that has been out of commission since February 2015 and will not likely return to service until February 2016. This PBF purchase is their second refinery buy this year and their fifth since 2010. The sophisticated Torrance refinery has a lot of upside potential for PBF but may be constrained by California transport fuel regulations. Today we take a closer look at the deal.
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.
They say that being in the right place at the right time has a lot to do with success in business. Two companies with infrastructure in the Eagle Ford can certainly attest to that. Koch Industries and NuStar Energy both owned pipeline assets supplying crude to refineries in South Texas long before the shale boom – putting them in a strong position to benefit from the flood of crude on their doorstep. Since 2011 both companies have expanded pipeline and terminal infrastructure to ship nearly 600 Mb/d of crude and condensate between them. Today we explain how.
In mid-September 2014 the joint venture partners in the shuttered St. Croix (U.S. Virgin Islands) HOVENSA refinery announced an agreement in principal to sell to a private equity fund. The refinery – shut since January 2012 - has been for sale since then but after losing $1.3 Billion in its last 3 years of operation has had trouble finding a buyer. Today we look at the hurdles a new owner has to overcome.
Two weeks ago (August 21, 2014) Plains All American announced their proposed “Diamond” crude pipeline project from Cushing, OK to Memphis, TN that will feed the Valero Memphis refinery starting in late 2016. The new pipeline will provide more direct access from Cushing to supplies of the light sweet crude this refinery processes that are being produced these days in the Williston, Denver Julesburg, Permian and Anadarko basins. Presumably the Diamond pipeline will replace existing arrangements where crude is shipped up the Capline pipeline to Memphis. That development looks to be another nail in the coffin for the northbound Capline crude trunk route between St James and Patoka, IL. Today we discuss the proposal and its consequences for Capline.
Vacuum gas oil or VGO is one of those mystery products talked about by refiners but barely understood by those of us that are not engineers. However it is an important intermediate feedstock that can increase the output of valuable diesel and gasoline from refineries. Lighter shale crudes such as Eagle Ford can produce VGO material direct from primary distillation. Today we shed some light on this semi-finished refinery product.
During the days when Gulf Coast refineries were dependent on crude imports for the majority of their feedstocks, tankers delivered crude from overseas markets. Those same tankers also played an important role in preventing refinery supply disruptions because they acted as a floating storage component in the supply chain. With waterborne imports to the Gulf Coast declining as domestic and Canadian production is increasingly delivered by pipeline, the buffer provided by floating storage will be much reduced. Today we continue our series looking at Gulf Coast crude storage needs in the shale era.
Reformate is a blending component that makes up about 30 percent of US gasoline supplies. It is also an important source of aromatics used as feedstocks for the petrochemicals industry. Ongoing changes in the US crude oil slate are reducing the volume of heavy naphtha available to feed catalytic reformer units that make reformate. At the same time better economics for lighter ethane feedstock are reducing the volume of aromatics produced as byproducts of olefin cracking. The result is a shortage of the aromatic materials used to produce a number of petrochemical intermediates such as polymers and fibers. But more changes are coming to the reformate market due to reductions in the use of reformate in gasoline. Today we look at the changing role of reformate.
Owning a refinery in the middle of the fastest growing shale crude basin sounds like a good idea. Calumet Specialty Products LP thinks so – they purchased the 14.5 Mb/d San Antonio refinery in December 2012 located at the heart of the Eagle Ford. Since then Calumet has set about expanding production and organizing more efficient crude transportation. But owning such a small refinery near the largest refining region in the world has its risks. Today we describe how location and crude supply advantages help keep this refinery competitive.
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.