Permian Basin crude production more than doubled since 2011 to reach nearly 2 MMb/d today, but that rate of increase has leveled off since prices crashed last year. Meantime 750Mb/d of long-haul pipeline takeaway capacity came online in the first half of 2015 - greatly exceeding today’s take-away requirements. And there is more to come next year when the 470 Mb/d Enterprise Midland-to-Sealy pipeline is expected online – leading to fears regional pipeline infrastructure is overbuilt. How about inside the Permian Basin? Today we start a series reviewing Permian gathering system build out.
Posts from Sandy Fielden
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.
Delays to the Enbridge Sandpiper project bringing greater volumes of Bakken crude onto the Enbridge Mainline system at Superior, WS threaten to limit the supply of crude to feed refineries in Quebec when Enbridge’s Line 9B reversal project comes online in November 2015. The market impact could push crude prices higher in North Dakota. Today we discuss the crude supply picture and possible impact when Line 9B opens up.
The cost to charter U.S. Flag Jones Act tankers that are used to transport crude and refined products along U.S. coastal waters is still as high as $75,000/day for medium-range 330 MBbl vessels. That’s four times what it costs for an equivalent foreign flag tanker. Higher charter rates – caused by tight vessel supply in a regulated market – have attracted investment from Kinder Morgan and other midstream companies and the tanker fleet will expand by 40% in the next 3 years. Today we discuss the market potential.
The Jones Act (see The Sea and Mr. Jones) is a federal statute requiring that all goods transported by water between U.S. ports be carried in U.S. Flag ships, constructed in the United States, owned by U.S. citizens, and crewed by U.S. citizens and/or U.S. permanent residents. Because of the regulations, operating expenses are higher for Jones Act vessels (as much as 2.7 times non-flag alternatives according to a U.S. Maritime Administration (MORAD) study in 2011). We have provided considerable coverage of the role that Jones Act vessels have played in the U.S. crude oil distribution system over the past 4 years since shale production increased domestic output including our Rock The Boat series in the spring of 2014. Subscribers to RBN’s Backstage Pass service can download a copy of the comprehensive “Rock The Boat” Drill Down Report that accompanied that series and contained a detailed inventory of the larger vessels and their owners.
A critical ingredient consumed in the production of aluminum is sourced exclusively from petroleum refineries. Complex refineries use coker units to break up residual fuel left over from initial crude processing to squeeze out the last drops of lighter components – leaving a solid carbon based residue known as petcoke. Without anode grade petcoke (GPC) there would be no aluminum industry. As we explain today aluminum producers are scrambling to address a looming petcoke shortage that could seriously disrupt their industry.
The acquisition of Williams Companies by Energy Transfer will create a midstream behemoth. The deal is expected to close during the first half of 2016 subject to regulatory approval. Once complete the main holding company Energy Transfer Corp (ETC) will be a C-Corp entity sitting atop Master Limited Partnerships (MLPs – see Masters of the Midstream for a more complete explanation of these structures) containing the assets of Energy Transfer Partners (ETP), Williams Energy Partners (WPZ), Sunoco LP (SUN) and Sunoco Logistics (SXL). The combined natural gas pipeline network will carry as much as 45% of U.S. Lower 48 dry gas production. Today we take a look at the natural gas infrastructure assets in the deal.
After a year’s delay due to permit issues, Enbridge now expects the expanded and reversed 300 Mb/d Line 9B pipeline to Montreal will come online next month (November 2015). The pipeline is an important cog in Enbridge’s Eastern Access and Light Oil Market Access expansion projects and will supply mostly light crude to two refineries in Quebec. As we explain today, the payload will travel a winding route to get to Montreal.
Petroleum coke (known as petcoke or “coke”) is produced by refinery coker units that break up residual fuel oil to squeeze out the last drops of lighter components used to make gasoline and diesel – leaving a solid carbon based residue. Petcoke is also the only commercial source of material used to manufacture electrolytic anodes that play a critical part in making aluminum. As a result – these industries are effectively joined at the hip - although you wouldn’t know it because the two rarely cooperate. As we explain in today’s blog - that may need to change going forward because a looming petcoke shortage could disrupt aluminum production and prices.
In a $38 Billion transaction announced September 28, 2015, Energy Transfer Equity (ETE) agreed to gobble up The Williams Companies in a deal expected to close during the first half of 2016. The combination of these two companies creates a U.S. midstream giant that will own infrastructure including gas pipelines carrying as much as 45% of U.S. Lower 48 dry gas production, processing capacity producing16% of domestic natural gas liquids (NGL’s) and crude oil pipelines in the Permian, Eagle Ford and Bakken. Today we take a look at the liquids infrastructure assets in this giant deal and provide a download of RBN’s maps of the infrastructure involved.
Crude production in the Niobrara shale formation is focused on two areas, the Denver-Julesburg (DJ) Basin in Northeast Colorado and the Powder River Basin (PRB) in Wyoming. Production has expanded in both basins (current output is about 435 Mb/d according to the Energy Information Administration) but much of the recent volume growth has come from the DJ basin. Expectations as recently as last year that production would expand to over 700 Mb/d in the next 4 years have been tempered by the crude price crash. A couple of large pipeline projects prompted last year by those production expectations have been cancelled since but others are still being built. Today we assess crude takeaway infrastructure in the DJ basin.
U.S. propane production growth in the shale era and the addition of new domestic and export terminal infrastructure has resulted in a radical transformation of the U.S. propane market. But even as the market responds to these positive developments, the memory of shortages and price spikes during the Polar Vortex winter of 2013-14 lingers. The market response since that crisis, and what further actions the industry might take to be better prepared for future market disruptions are the subjects of RBN’s latest Drill Down report reviewed in today’s blog (click here for a preview of the report: Next To You: A Transformation in Propane Markets).
With increasing production near demand regions, better connectivity from both pipeline and rail, and export volumes that can be bid away from global markets, the U.S. propane industry is in a much better position to handle a “Perfect Storm” of extreme demand events than it was in the winter of 2013-14. Nevertheless, today’s propane market brings with it a number of challenges, including greater exposure of domestic propane to global markets, more complex inter-regional supply dynamics, a more diverse supply chain, all in the context of limited domestic demand growth. In today’s blog we conclude our analysis of the U.S. propane market.
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.
The opening up of Mexico’s retail liquefied petroleum gas (LPG) market could provide significant opportunities for U.S. propane and butane producers, as well as midstream companies and exporters. If exports of U.S.- sourced LPG are to increase, though, it would help to have a more robust and efficient system than presently exists for transporting the fuel to the U.S.-Mexico border and, from there, to key LPG consumption markets within Mexico. Today, we continue our look at Mexican LPG imports with a review of existing and planned pipelines.
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).