For a few years now, Buckeye Partners’ plan to revise the current east-to-west refined products flow on its Laurel Pipeline across Pennsylvania has pitted Midwest refiners against their Philadelphia-area brethren — and gasoline and diesel marketers in western Pennsylvania. Each side has good arguments. Midwest refiners note that westbound volumes on Laurel have been declining through the 2010s, and assert that making the western part of the pipeline bidirectional would result in higher utilization of the line and enhance competition in central Pennsylvania, Maryland and eastern West Virginia. Pittsburgh-area marketers counter with the view that allowing refined products to flow east on a portion of Laurel would hurt competition in Pirates/Steelers/Penguins Country, while Philly refiners — their ranks now thinned by the planned closure of the fire-damaged Philadelphia Energy Solutions (PES) facility — say Buckeye’s plan would further threaten their economic viability. Amid all this, might there be a “perfect-world” solution? Today, we provide an update on this still-in-limbo project and discuss a few possible paths forward.
Independent refiner PBF Energy on June 11 announced its plan to acquire Shell Oil’s Martinez, CA, refinery for about $1 billion; the deal is expected to close by the end of 2019. The purchase will give PBF its sixth U.S. refinery and add 157 Mb/d to the company’s existing 865-Mb/d refining portfolio, pushing its total capacity past 1 MMb/d. Post-acquisition, PBF will retain overall fourth place in the U.S.
Philadelphia Energy Solutions (PES) announced last week (on June 26) that it was shutting down its 335-Mb/d refinery in Philadelphia, PA. This announcement came just five days after a major fire destroyed a portion of the refinery, which turned out to be the last straw for the facility that has been struggling financially for many years. Today, we consider the various market impacts that will likely follow the closure of the PES refinery, including its effect on fuel supply, where the closure leaves refinery production capacity in the region and how the refined product supply will need to adjust in response.
For some time, U.S. motor fuel exports to Mexico had been increasing at a healthy pace, reliably filling the void created by a series of production setbacks at Pemex’s refineries south of the border. From 2014 to 2018, U.S. gasoline exports to Mexico soared by more than 160%, from an average of 197 Mb/d five years ago to 517 Mb/d last year. Diesel exports rose by nearly 130%, to 279 Mb/d, over the same period. But that export-growth momentum has since sagged — in fact, export volumes for both gasoline and diesel actually declined in the first few months of 2019, primarily due to logistical challenges within Mexico. Also, Mexico’s new president has proposed ambitious plans to boost state-owned Pemex’s refining capacity, possibly posing a longer-term threat to U.S. exporters. So, is the boom in refined-product exports to Mexico over? Today, we examine what’s behind the downshift, and what the Mexican government’s effort to reinvigorate Pemex’s existing refineries — and build an entirely new one — may mean for U.S. gasoline and diesel exports in the 2020s.
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.
With Petróleos Mexicanos’ (Pemex) refineries struggling to operate at more than 30% of total capacity, gasoline pumps across Mexico are more likely to be filling up tanks with fuel imported from the U.S. than with domestic supply. This arrangement works well for U.S. refiners, who are running close to flat-out and depending on export volumes to clear the market. But now, the Mexican government has shut a number of refined products pipelines to prevent illegal tapping, and that’s had two consequences: widespread fuel shortages among Mexican consumers and a logjam of American supplies waiting to come into Mexico’s ports. Today, we explain the opportunities and risks posed to U.S. refiners that have ramped up their involvement with — and dependence on — the Mexican market.
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.
During 2018, U.S. crude oil, natural gas and NGL production hit new all-time highs almost every month. Oil production grew by a staggering 1.7 MMb/d from January to December, an increase of about 18%. NGLs soared even more: by 27%, up 1.0 MMb/d over the same 12-month period. Natural gas production zoomed skyward by 10 Bcf/d, a gain of about 13%. All this new supply came on in a price environment marked by wild swings. WTI ran up from $60/bbl to $75, then collapsed below $50. Henry Hub gas spiked to nearly $5/MMBtu, then beat a hasty retreat back to the $3/MMBtu range. Permian gas traded negative. Ethane prices blasted to the moon (62 c/gal), then crashed back to earth (below 30 c/gal). Is this the way it’s going to be? Massive production growth, extreme price volatility, widespread market uncertainty? It’s impossible to answer such a question, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2019 has in store for us.
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.
Dominator. Showboat. Brass Monkey. These are not player names in the re-established XFL; these are project names given to colossally proportioned drilling pads in the Permian and Appalachia. A single one of these well pads can be home to 20, 30, even 60 or more permitted well spots, each with miles-long laterals branching out in multiple directions. In today’s blog, we begin a series exploring the motivations that sparked this trend to larger pads and discuss the impact they’re having on the upstream and midstream sectors.
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 IMO 2020 rule, which calls for a global shift to low-sulfur marine fuel on January 1, 2020, is likely to require a ramp-up in global refinery runs — that is, refineries not already running flat out will have to step up their game. Why? Because, according to a new analysis, the shipping sector’s need for an incremental 2 MMb/d of 0.5%-sulfur bunker less than 13 months from now cannot be met solely by a combination of fuel-oil blending, crude-slate changes and refinery upgrades. The catch is, most U.S. refineries are already operating at or near 100% of their capacity, so the bulk of the refinery-run increases will need to happen elsewhere. Today, we continue our look into how sharply rising demand for IMO 2020-compliant marine fuel may affect refinery utilization.
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.
The planned implementation date for IMO 2020 is still more than a year away, but this much already seems clear: even assuming some degree of non-compliance, a combination of fuel-oil blending, crude-slate shifts, refinery upgrades and ship-mounted “scrubbers” won’t be enough to achieve full, Day 1 compliance with the international mandate to slash the shipping sector’s sulfur emissions. Increased global refinery runs would help, but there are limits to what that could do. 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 discuss Baker & O’Brien’s 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.