U.S. crude oil, NGL and gas markets have entered a new era. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the flow rates coming over the next few years, if not for access to global markets. This year, the U.S. may export 20-25% of domestic crude production, 15% of natural gas and 40% of NGLs from gas processing, and those percentages will continue to ramp up. What will this massive shift in energy flows mean for U.S. markets, and for that matter, for the rest of the world? The best way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for Energy xPortCon 2019. Warning!: Today’s blog is a blatant advertorial for our upcoming conference.

The implementation date for IMO 2020, the international rule mandating a shift to low-sulfur marine fuel, is less than 12 months away. It’s anyone’s guess what the actual prices of Brent, West Texas Intermediate (WTI) and other benchmark crudes will be on January 1, 2020, or how much it will cost to buy IMO 2020-compliant bunker a year from now. What is predictable, though, is that the rapid ramp-up in demand for 0.5%-sulfur marine fuel is likely to affect the price relationships among various grades of crude oil, and among the wide range of refined products and refinery residues — everything from high-sulfur residual fuel oil (HSFO, or resid) to jet fuel. The refinery sector is in for an extended period of wrenching change, and today we conclude our blog series on the new bunker rule with a look at the structural pricing shifts needed to support the availability of low-sulfur marine fuel.

One way or the other, all of 2018’s Top 10 blogs had something to do with infrastructure. There’s not enough. Or it’s taking too long to come online. Or there is too much being built too soon. Even the financial underpinning of U.S. energy infrastructure development — the MLP model — ran into tough sledding in 2018. Then, toward the end of the year, all of the best-laid infrastructure planning got whacked by the crude-market wild card: prices crashing below $50/bbl. We scrupulously monitor the website “hit rate” of the RBN blogs that go out to about 26,000 people each day and, at the end of each year, we look back to see what generated the most interest from you, our readers. That hit rate reveals a lot about major market trends. So, once again, we look into the rearview mirror to check out the top blogs of the year based on the number of rbnenergy.com website hits.

While U.S. refineries are again running hot and heavy after the end of this year’s seasonal fall maintenance period, Mexico’s refineries have continued to struggle to operate at more than 30% of their capacity, a decline that is exacerbated by that country’s tumbling oil production. In recent years, Mexico’s dismal refinery utilization rate has been a boon for U.S. refiners on the Gulf Coast who can ship, pipe or truck gasoline to America’s southern neighbor in short order. Now, Mexico’s new president, Andrés Manuel López Obrador (AMLO), is pushing to solve Mexico’s refinery problems by building a new one. Today, we discuss Mexico’s growing dependence on U.S. gasoline, and whether building a new refinery south of the border will change things.

The planned shift from 3.5%-sulfur marine fuel to fuel with sulfur content of 0.5% or less mandated by IMO 2020 on January 1, 2020, will require a combination of fuel-oil blending, crude-slate changes, refinery upgrades and, potentially, increased refinery runs, not to mention ship-mounted “scrubbers” for those who want to continue burning higher-sulfur bunker. That’s a lot of stars to align, and even then, there’s likely to be at least some degree of non-compliance, at least for a while. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we continue our analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.

It’s been more than a year since Hurricane Harvey dumped 50 inches of rain on Houston and its environs, but memories from those fateful days remain remarkably fresh. Harvey is not only unforgettable, it put a spotlight on just how important Texas refineries — and the refined-products pipeline infrastructure connected to them — are to the rest of the U.S. For several days, more than half of the Gulf Coast’s refining capacity was offline. Major pipelines transporting gasoline, diesel and jet fuel to the East Coast and the Midwest shut down too. But how do Harvey’s impacts on refining and refined products markets compare with the effects of other major hurricanes this century? Today, we conclude our series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.

Twenty-five years ago, in 1993, the Mexican national oil company — Petróleos Mexicanos, or Pemex — purchased a 50% stake in Shell’s Deer Park, TX, refinery. The joint-venture partners entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we begin a two-part series on the joint venture with a look at how Pemex has benefitted.