Crude oil — often mistakenly described as a single, standardized commodity — is anything but uniform. Every stream has its own chemical fingerprint, including differences in density and sulfur content. Today, we’ll dig into why crude quality matters and how it can make a real difference to the bottom line.
Increasing U.S. shale oil production has benefitted many U.S. refineries, but along the Gulf Coast, the primary beneficiaries have been in Texas. As production increased in the Permian and Eagle Ford plays, new pipelines were built to supply refinery centers in Corpus Christi, Houston, and Beaumont/Port Arthur. In contrast, the availability of shale crude by pipeline to refineries in Southeast Louisiana has lagged. However, new pipeline capacity to the crude hub in St. James, LA, is about to change the dynamic in a major way. Today, we continue our series on St. James by discussing the Bayou State’s refinery infrastructure and how new pipelines could impact refinery crude slates.
The combination of rising condensate demand as new splitter capacity came online and falling conde supply resulted in just what you’d expect — higher conde prices. Worse yet for the companies that made throughput commitments for those new splitters, the once-favorable price differentials between conde and light-crude benchmarks West Texas Intermediate (WTI) and Louisiana Light Sweet (LLS) have been turned on their heads, and a number of splitters are operating at far less than capacity. Today, we continue our look at the roller-coaster world of conde, this time focusing on conde prices and differentials, and on the forces that may change the conde market once again.
Maya, Mexico’s flagship heavy crude, has been a key staple in the diet of U.S. Gulf Coast refiners for a long time, and it has faithfully served as a price benchmark for nearly all heavy crude oil traded along the U.S. Gulf, and points beyond. Maya’s price, relative to lighter benchmark grades such as Louisiana Light Sweet (LLS) or Brent, provides ready insight into the profitability of heavy oil (coking) refiners. But production of Maya peaked in 2004 and has declined considerably since then, raising questions about its continuing efficacy as a price benchmark. Now it’s come to light that a component of the Maya price formula was changed effective January 1, 2017. Although the change—related to the formula’s fuel oil price component—might be viewed as a relatively minor tweak, it raises new questions about this important heavy oil price benchmark. Today we begin a two-part series on Maya crude, the new price formula and its potential effects.
On December 18, 2015, Congress and President Obama ended the 40-year ban on U.S. crude oil exports to countries other than Canada. Today the arbitrage window doesn’t make much economic sense for most exports – Light Louisiana Sweet on the Gulf Coast is about the same price as Brent in the North Sea. But the prospect of selling crude abroad remains tantalizing for a depressed U.S. upstream, and U.S. producers have begun to consider the possibilities for more significant export volumes. But does the U.S. have the right stuff? Will the qualities of U.S. crudes be competitive in global markets? In today’s blog, we begin a series to consider the qualities of U.S. crudes that are likely to be favored by international crude buyers.
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.
When you transport crude to market by pipeline its going to get mixed up with other folk’s production being shipped on that pipeline unless you have an exclusive pipeline – which is not the norm. Some pipeline systems use a batch mechanism to separate individual parcels but the usual approach is to mix together like crudes in a common stream. When that happens the pipeline operator uses a quality bank to credit or debit shippers for differences in the quality between the crude they put in and what they take out of the pipeline. Today we explore how quality banks work.
Last week (February 2013) EOG Resources told analysts that most Eagle Ford oil production should be classified as condensate rather than crude oil. They backed up their assertion with a chart of production quantity and API quality indicating 70 percent of production is condensate. Current forecasts indicate that translates to condensate production of over 500Mb/d in South Texas during 2013. Today we examine the evidence that EOG presented.
Crude oil production in the Eagle Ford has ramped up from less than 50 Mb/d two years ago to almost 400 Mb/d today, and the growth shows no sign of slowing down. In most reports and statistics, all of this volume shows up as crude oil. But it’s not. Between 60%-70% of this production is condensate – a hydrocarbon classification that is somewhere between crude oil and natural gas liquids. It is valued differently from crude, can require handling different from crude, and can go into markets different from crude. But neither is it a natural gas liquid. Condensates are produced in the field, not extracted from a wet gas stream by a cryogenic processing unit. Condensates are neither fish nor fowl.
