A question we get asked all the time these days is whether or not U.S. crude output has begun to decline yet and if so by how much? We don’t actually think the answer makes a lot of difference to the market - especially when you consider changing imports and inventory. But ever since the OPEC meeting last November (2014) failed to take action to reduce output to support oil prices - market watchers have placed a lot of emphasis on when U.S. shale producers would respond by cutting production. So regardless of the merits of the question we are all living in a marketplace where knowing the “real” state of U.S. production – and whether it is up or down – has become a big deal. To that end today we look at crude production data from the Energy Information Administration (EIA).
Daily Energy Blog
This month the North Dakota Industrial Commission (NDIC) indicated they are leaning towards leniency in their treatment of operators that have drilled but not completed wells within the one-year time frame permitted. Instead of assuming such wells are abandoned, which would otherwise mean an expired drilling permit and about $200,000 in plugging costs, – the State plans to give operators more time. That possibility opens up a whole new underground storage option for producers struggling to make ends meet. Today we explain the NDIC plan.
Floating production, storage and offloading vessels—FPSOs, for short—allow for hydrocarbon production in waters too deep for conventional offshore platforms. While FPSOs have been in limited use around the world since the mid-1970s, they remain a relative rarity in the Gulf of Mexico (GOM), mostly because oil and natural gas has been available in shallower parts of the Gulf closer to shore. Now, Royal Dutch Shell will be taking a spanking-new FPSO into the deepest waters yet--9,500 feet, or almost two miles down--for its mammoth Stones development 200 miles off the Louisiana coast. Today, we look at the Stones project, the growing role of FPSOs, and the long-term perspective taken by exploration and production (E&P) companies in the GOM.
Blueknight Energy Partners’ 100 Mb/d Knight Warrior pipeline is currently under construction and due online in Q2 2016 to deliver crude from the developing Eaglebine play to the Houston Ship Channel. It complements the 60 Mb/d Sunoco Logistics Eaglebine Express pipeline to Nederland, TX that opened last December. Today we discuss how the promising but relatively complex nature of Eaglebine drilling could scare off producers until prices move substantially higher than today’s levels.
Our recent analysis of Houston area crude infrastructure found new pipelines running half full as more capacity comes online and storage only half utilized as midstream operators continue to plan expansions. Add the current crude production slowdown to that equation and it could spell trouble for midstream companies. Today we ponder the fate of midstream investment in Houston crude oil infrastructure.
Even as Houston area crude oil storage – at refineries and commercial terminals – remains just half utilized according to data from Genscape, midstream operators are busy building more tanks. About 7 MMBbl of storage is under construction now and plans have been announced this year to build another 11 MMBbl. Today we detail plans to expand crude storage in the Houston area.
For the past several months shippers in Midland, TX – in the middle of the prolific Permian Basin - have been paying premiums up to $2/Bbl over the benchmark Cushing, OK trading hub price for West Texas Intermediate (WTI) crude. That means shipping WTI from Midland to Cushing is a money losing proposition. Historically Cushing WTI has traded at a premium to Midland – usually at least covering the ~$1/Bbl pipeline tariff. Today we explain how traditional price dynamics have been turned upside down.
Close analysis of Houston area crude storage indicates it is only 52% utilized today even as regional crude inventories have reached record levels. Meeting refinery operational needs appears to be the main use of area storage – rather than speculative gains from buying today’s cheap oil to store and sell later. Today we continue our analysis of Houston area refinery infrastructure.
Pipelines delivering crude to Houston from the South Texas Eagle Ford are estimated to be half empty. Yet over 200Mb/d of crude is shipped from that basin to refineries in Houston and further east along the Gulf Coast by barge. One of the key reasons appears to be that local traffic congestion and a lack of adequate throughway pipeline capacity past Houston pushes barrels not needed locally onto the water to reach refineries in Louisiana. Today we explain the Houston crude traffic problem.
Last Friday (August 14, 2015) the Department of Commerce (DOC) revealed to the press that they would approve a handful of applications to export U.S. domestic light crude to Mexico under a Licensed “swap” arrangement that involves importing the same volume of heavy crude to the U.S. from Mexico. The Licenses are likely to be awarded to Mexican national oil company PEMEX or its affiliates and will last for a year starting at the end of this month (August 2015). Today we update our earlier analysis of Mexican crude swap exports.
During the first 7 months of 2015 the U.S. experienced record setting refinery crude processing and utilization rates. By the end of July crude inputs topped 17 MMb/d for the first time and nationwide refineries ran at over 96% of operable capacity - reaping the rewards of robust margins. But the party has been marred by a number of unexpected outages – the latest of which brought down a 250 Mb/d unit at BP’s Whiting, IN refinery last weekend – causing a spike in Chicago gasoline prices. Today we ponder why outages may be occurring and the upcoming impact of overdue fall maintenance.
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.
Crude by rail (CBR) shipments from North Dakota to West Coast destinations peaked in January 2015 at 170 Mb/d – falling since then to average 140 Mb/d in 2015, January through May. The vast majority of these shipments have moved to four refineries in Washington State – providing a cheaper alternative to the Alaska North Slope (ANS) crude staple these refineries have run for decades. There is big potential to expand CBR shipments to West Coast Ports and to California but building the infrastructure has proven painstakingly slow. Today we discuss the long term fate of West Coast CBR.
Crude oil distribution to Houston area refineries is still being re-plumbed to reflect the ongoing transition to domestic supply. Estimates of current crude pipeline flows indicate as little as 43% of inbound pipeline capacity is being used - but new projects could add over 1 MMb/d to inbound supplies by early next year. Today we start a new series reviewing how well crude infrastructure is meeting Houston area logistic challenges.
Yesterday (August 3, 2015) Brent crude closed under $50/Bbl for the first time since January 2015. At that price expensive crude-by-rail (CBR) freight costs to the East Coast leave Bakken producers with netbacks not much over $30/Bbl. Yet CBR shipments to the East Coast were still over 400 Mb/d in May 2015 according to the Energy Information Administration (EIA). By 2017 there should be adequate capacity to get all Bakken crude to market by pipeline. But direct pipeline competition against rail to the East Coast is not expected until at least 2020. Today we look at the future of East Coast CBR.
