Mexico has emerged as an important and growing market for U.S. natural gas producers, and for U.S. midstream companies scrambling to develop gas pipelines to serve Mexico’s gas consumers. Meanwhile, U.S. gasoline, diesel and liquefied petroleum gas (LPG) exports to Mexico are also up. Petróleos Mexicanos (Pemex)—the state-owned hydrocarbon giant, now in the midst of a major reboot—is on the hunt for private-sector partners to help revive Mexico’s sagging oil and gas production, and U.S. oil producers and Pemex are planning their first swaps of crude. Today we highlight RBN Energy’s latest Drill Down report examining the changing yins and yangs of cross-border energy relations.
Eager to boost oil and natural gas production, the government of Mexico is in the midst of a multi-year effort to introduce more private-sector involvement and competition. The hope is that a series of reforms will lead to more investment and—over time—a Mexican energy sector that more closely resembles that of Mexico’s amigos North of the Border. Today, we continue our look at the ongoing transformation of U.S.-Mexico hydrocarbon trade and what it may mean for energy companies on both sides of the Rio Grande.
Mexico’s energy relationship with the U.S. is undergoing radical changes as its oil production sags, its refineries produce too much high-sulfur fuel oil and too little gasoline and diesel, and its imports of U.S. natural gas and transportation fuels rise. Add to this already complicated story the Mexican government’s efforts to inject competition and private-sector participation into a national energy sector long-dominated by state-owned Petróleos Mexicanos (Pemex) and that company’s plan to swap light U.S. crude for heavy Mexican oil. In today’s blog, “With A Little Help From My Friends—Mexico’s Oil Sector in a State of Flux,” Housley Carr begins a look at the ongoing transformation of U.S.-Mexico hydrocarbon trade and what it may mean for U.S. players—and Pemex.
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.
Did you miss our School of Energy a few weeks back in Houston? Not a problem! The entire School of Energy conference is now available online in streaming video format. The conference video, presentation slides and spreadsheet models are available for purchase as individual Modules or as a full conference package. It’s the next best thing to being there! School of Energy is unlike other natural gas, NGL or crude oil conferences. It combines all three! And the curriculum includes a comprehensive analysis of current energy markets and in-depth instruction on how to use RBN spreadsheet models covering everything from production economics to gas processing. We walk through key developments for each of the three hydrocarbons including the increasingly important links between them. Fair warning – today’s blog is a blatant advertorial.
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.
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.
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 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.