After several years of development, Shell’s $6 billion Pennsylvania Petrochemicals Complex — the first of its kind in the Marcellus/Utica shale play — is really taking shape about 30 miles northwest of Pittsburgh. The facility, which will consist of a 3.3-billion-lb/year ethylene plant and three polyethylene units, is in its final stages of construction, as is a pipeline that will supply regionally sourced ethane to the steam cracker. When the Falcon Pipeline and the PPC comes online, possibly as soon as 2022, they will provide a new and important outlet for the vast amounts of ethane that is now either “rejected” into natural gas for its Btu value or piped to Canada, the Gulf Coast, or the Marcus Hook export terminal near Philadelphia. Today, we discuss progress on the Marcellus/Utica’s first world-class petrochemical complex and what it will mean for the play’s NGL market.
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Daily energy Posts
In the spring of 2020, as the COVID-19 crisis started hitting the energy sector hard, many refiners made the tough decision to dramatically cut back capital spending plans and operating costs for the year in order to weather the storm. While these cuts were swift and sizeable, they were not absolute — they couldn’t be, given that refining is a capital-intensive industry with complex assets that require seemingly constant maintenance, equipment swap-outs, and upgrades. And then there’s the added pressure that refiners also need to invest in keeping their facilities in compliance with changing environmental rules, and to consider the overall impact of investments in new, “greener” fuels, such as renewable diesel, that may help them improve their profitability going forward. Today, we look at refiner capital spending in the context of recent history and highlights some of the growth projects being pursued in the sector.
Motor gasoline, diesel, and jet fuel need to be delivered in large volumes to every major metropolis in the U.S. While most big cities are well-served, some by multiple pipelines or a combination of pipelines and barges, others are more isolated and susceptible to supply interruption. Nashville, the home of country music, is one such place; so are Chattanooga and Knoxville to its east. All three Tennessee cities depend heavily on stub lines off the Colonial and Plantation refined-products pipeline systems as they work their way from the Gulf Coast to the Mid-Atlantic states. When supplies on these pipes are interrupted — and they have been from time to time — these cities can experience shortages and price spikes, and be forced to turn to trucked-in volumes from Memphis and elsewhere. Today, we discuss a supply alternative now under development that will pipe motor fuels south from BP’s Whiting refinery in northwestern Indiana to a proposed Buckeye Partners storage and distribution terminal just west of Nashville.
For a few years now, refineries in the eastern part of PADD 2 — feedstock-advantaged and capable of producing far more refined products than their regional market can consume — have been eyeing the wholesale and retail markets to their east in PADD 1. Their thinking has been, if they could just pipe more of their gasoline and diesel into Pennsylvania, upstate New York, and adjoining areas, they could sell the transportation fuels at a premium and take market share. Well, things are looking up for PADD 2 refineries pursuing this strategy. Not only has new pipeline access to the east been opening up, but PADD 1’s refining capacity has been shrinking fast, leaving East Coast refineries less able than ever to meet in-region demand. Today, we discuss recent developments in the battle for refined-product market share in the Mid-Atlantic region.
It has been nearly a year since the novel coronavirus was first detected in China — that’s right, a year. In that time, we have seen significant parts of the world come to a near standstill, become all too familiar with video conferencing, and canceled family vacations and business travel. The fact that many of us have been stuck at home has wreaked havoc on the U.S. refining industry, with plummeting utilizations and some facilities shutting down, either temporarily or permanently. And, depending on how the U.S. transportation sector rebounds from the pandemic in 2021 and beyond, more refinery closures may be on the horizon. Today, we look at the U.S. facilities that are shutting down and tally up the capacity lost so far.
Everywhere you look these days, someone is talking about hydrogen and, if you’re not well-versed in emerging technologies aimed at reducing carbon, you may not know what any of it means. A quick internet search isn’t much help either, as you will likely get lost quickly in discussions of fuel cell efficiency and electrolysis technology developments, not to mention the various “colors” of hydrogen and the myriad of ways it can be stored and transported. Don’t bother turning to your traditional green energy gurus either, as hydrogen is just one of many competing approaches to reducing the world’s carbon footprint, and electric vehicle folks like Elon Musk aren’t big fans. All the same, hydrogen news and investment plans seem to proliferate daily, and understanding this fuel — which, by the way, is not new to the energy space — seems prudent. At least that’s our view, which is why we today start a series to help us hydrocarbon experts unravel the mysteries behind the recent hydrogen ruckus.
For the past several months, U.S. refineries have been producing more distillate than demand warrants, resulting in a glut of distillate fuels, especially ultra-low-sulfur diesel and jet fuel. The disconnect between supply and demand has been particularly stark in the Gulf Coast region, where just a couple of weeks ago distillate stocks sat 39% above their 10-year average after coming perilously close to tank tops in August. The culprit, of course, is COVID-19, or more specifically the effects of the pandemic on air travel and the broader economy. Demand for motor gasoline rebounded more quickly than demand for ULSD and jet fuel, and refineries churned out more gasoline to keep up, but that results in more distillate too. Now, finally, there are signs that distillate stocks may be easing back down. Today, we discuss the build-up in ULSD and jet fuel stockpiles, the ways they might revert to the norm, and the potential for storing distillate now and selling it at a higher price later.
If you’ve filled up the tank in your car, SUV, or pickup in the past few days, you probably bought your first batch of winter-blend gasoline since the spring. It’s unlikely that you noticed a difference — only a refining geek with a nose for this sort of thing would — but winter gasoline has a higher Reid Vapor Pressure than summer gasoline, and therefore evaporates more quickly and emits more fumes. There’s a logic to EPA’s mandated switchover from lower-RVP gasoline to higher-RVP gasoline each September, and their switch back to lower-RVP each April/May. For one thing, using different gasoline blends during the colder and warmer months helps ensure that your engine runs well year-round; for another, reducing gasoline vapor pressure in the summer reduces emissions that contribute to smog. Today, we discuss gasoline RVP, why it matters, and how refineries ramp it up and down. (A hint is in the blog’s title.)
Over each of the past eight years, we’ve opened the doors at RBN’s School of Energy with updated analytical models, new subject modules, and timely special features that have reflected the evolution of energy markets from the early days of the Shale Revolution and $100/bbl crude oil, through the price crash of 2015-16 and the incredible 2017-19 rebound. But these market shifts pale in comparison with what’s happened so far in 2020: a global pandemic, crude crashing to negative $37/bbl, a wipeout in LNG exports, a Cat 4 hurricane into Lake Charles — it just seems to keep on coming. Which means there has never been a more important time to reassess market analytics in the context of these tectonic shifts in the energy industry. That is exactly what we’ll cover today in this blatant advertorial for RBN's Fall 2020 School of Energy.
For U.S. refineries, the severe demand destruction that occurred this spring led to the worst financial performance in recent history. Not only did refiners produce less diesel, motor gasoline, and jet fuel in the second quarter than any quarter in recent memory, their refining margins were sharply lower than the historical range — a one-two punch that hit their bottom lines hard. The situation has improved somewhat this summer, but it’s still tough out there. So tough, in fact, that it’s reasonable to ask, does the coronavirus and its impacts to the energy sector signal the end of an era for refiners across the U.S.? Today, we review the decline in fuel demand and profitability in the second quarter and discuss the uncertainties refiners face in the second half of 2020 and beyond.
The global effort to stop the spread of COVID-19 brought the commercial aviation sector to its knees, and slashed demand for jet fuel to its lowest level in 50 years. That, combined with lower demand for motor gasoline and — to a lesser extent — diesel, forced refineries in the U.S. and elsewhere to substantially reduce their crude oil input and to make major changes in their operations, all with the aim of bringing refined product supply and demand into closer balance. After a horrific spring, U.S. jet fuel production and demand have been rebounding somewhat in recent weeks, but getting back to pre-coronavirus levels may take a long time. Today, we review the flight from hell that the jet fuel market has suffered through so far this year, and how it is affecting refineries.
Earlier this month, Shell announced that it was exploring the sale of yet another refinery — this time, it is the company’s Convent facility in Louisiana, which is one of the two refineries in the state that remain with Shell from the unwinding of its former joint venture with Saudi Aramco. Convent, with a capacity of 240 Mb/d, is near the middle of the pack in terms of refinery size and possesses some unique characteristics that could make it an attractive option for the right buyer and market conditions. But Shell’s announcement also raises a question, namely, how does the prospective sale compare with the company’s stated intent to focus on a smaller set of refineries integrated with Shell’s key trading hubs and petrochemicals operations? Today, we review the refinery’s characteristics and how it stacks up against its nearby rivals.
They’re generally small in size, but renewable diesel refineries are popping up in many parts of the U.S., incentivized by government programs aimed at reducing carbon emissions and very gradually weaning Americans — and Canadians — from crude oil-based diesel fuel. Recently, HollyFrontier Corp. announced that it will be converting its decades-old Cheyenne, WY, refinery into a renewable diesel facility. While the news of another entrant into the renewable diesel market is not surprising, the complete shutdown and transformation of an existing refinery for this purpose marks only the second time this has occurred in the U.S. Today, we discuss HollyFrontier’s plans and provide an update on renewable diesel supply and demand dynamics.
The demand destruction caused by COVID-19 hasn’t only hurt producers and refiners; it’s also slowed the development of a number of planned midstream projects. In fact, the only multibillion-dollar crude-related project to reach a final investment decision (FID) during the pandemic is TC Energy’s Keystone XL, which in late March won financial backing from Alberta’s provincial government. But Keystone XL soon hit another snag, this time in the form of U.S. district and appellate court rulings that vacated the project’s Nationwide Permit 12 for construction in and around hundreds of streams and wetlands along the U.S. portion of the pipeline’s route in the U.S. More important, the courts also put on ice — at least for now — the use of the general water-crossing permit for other new oil and natural gas pipelines as well. As we discuss in today’s blog, that could result in delays and legal challenges to dozens of projects that midstreamers and their counterparties have been counting on.
U.S. exports of motor gasoline and diesel to Mexico increased steadily from 2013 through 2018 as demand for refined products south of the border increased and throughput at Pemex’s six older, investment-starved refineries declined. U.S.-to-Mexico shipments of gasoline and diesel sagged in 2019, though, as Pemex started to implement a major refinery rebuilding program, and fell further in the spring of 2020 as the social and economic effects of COVID kicked in and Mexican demand for motor fuels plummeted. So what’s ahead for U.S. refined product exports as Mexican demand gradually rebounds later this year and in 2021? As we discuss today, that will largely depend on the Mexican government’s determination to have its debt-laden energy company produce gasoline and diesel at a loss and proceed with expensive refinery projects.
On Thursday, June 18, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) to reset the index that’s used to make annual changes to the rate ceilings for interstate pipelines that transport crude oil, refined products, and other hydrocarbon liquids. Every year, the highest rate an indexed oil pipeline can charge goes up or down — almost always up — using the FERC index. The commission’s new proposal, which would become effective in July 2021, follows an already-approved index adjustment that will take effect a week from Wednesday, on July 1. Taken together, the two changes would reduce the maximum annual increase in the rate ceiling from more than 4% now to less than 1%, which could have a major impact on liquids pipeline owners. Today, we discuss the NOI, the meaning of the pipeline index, where it came from, and where it might be headed.