When it comes to midstream development in the Northeast, Appalachian natural gas producers have learned by now not to hold their breath. The region is notorious for its staunch environmental opposition to hydrocarbon infrastructure and its propensity for sending gas pipeline projects to the trash pile. Against all odds, however, midstream development in the region has thawed in recent months, in large part spurred by the unlikely advancement of Mountain Valley Pipeline (MVP), the long-embattled project to move up to 2 Bcf/d from the Appalachia gas supply basin to the Transco Corridor, which runs north-south along the Eastern Seaboard. In today’s RBN blog, we take a look at historical flows on Williams’s Transco Pipeline and what they can tell us about how MVP and Transco’s own planned expansions might reshape gas flows along the corridor.
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WTI was down again by another 1.4% on Monday following a 2.5% drop on Friday as the market remains unimpressed by OPEC+ production cuts announced last Thursday. WTI settled at $73.04/bbl, off $1.03/bbl. OPEC+ announced its intentions to reduce production by approximately 2.2 MMb/d for Q1 2024,
It is winter in propane country, and even though it has been a relatively mild one so far, propane prices have been remarkably weak. For one thing, the ratio of Mont Belvieu propane to WTI crude oil has been in the dumper all year, averaging a paltry 35% since March. Last year for the same peri
Daily Energy Blog
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.
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.)
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.
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.
Mexican demand for motor gasoline and diesel has plummeted this spring due to COVID-19 — so has demand for LPG. So far, Pemex — Mexico’s state-owned energy company and by far the country’s largest supplier of these commodities — has responded by slashing how much gasoline, diesel and LPG it is importing from the U.S. and holding its own production steady, despite the fact that Pemex’s refining margins are now deep in negative territory. What does Pemex’s focus on money-losing refining mean for U.S. exports to Mexico going forward? Today, we begin a short series on the ongoing competition between U.S. refiners and Pemex for market share south of the border.
COVID-19 has created a number of challenges across the energy value chain, including lower demand for motor gasoline and jet fuel and, subsequently, surplus crude oil. However, even with diminished demand, the facilities that produce and process these fuels have to keep operating at some level, as do petrochemical plants. Workers in the energy industry are considered essential due to the importance of having fuel available to power vehicles and manufacturing facilities, natural gas to enable continued operation of power industries, and logistical infrastructure to ensure that feedstock supply can make it to processing facilities and eventually consumers. Given the need for round-the-clock operations, COVID-related social distancing measures have presented a unique challenge for refinery and petrochemical facilities. To maintain adequate staffing while protecting personnel from the coronavirus, these facilities have been making major adjustments. If, as we all hope, things begin moving back toward “normal” in the coming months and refinery and petchem utilization ramps up, these efforts to keep workers safe will only gain in significance. Today, we discuss staffing issues in these key industry sectors during the pandemic.
The COVID-19-induced social isolation and subsequent economic slowdown have caused major drops in U.S. refined products consumption, especially gasoline and jet fuel, which have experienced declines of as much as 44% and 70%, respectively, relative to similar periods in 2019. Diesel fuel consumption has been off as much as 20% on the same basis, and given that COVID is a global crisis, product exports have also fallen. As a result, U.S. refinery utilization has dropped to less than 70% for the last few weeks, the lowest levels since September 2008 during Hurricane Ike. All this presents refiners with two challenges: (1) reduced total demand; and (2) the disproportionate decline in gasoline and jet fuel. Each refinery is configured differently and has a varying degree of flexibility to react to these challenges. Today, we discuss what refiners can do to adjust operations and product yields, and examine the point at which some refineries might be forced to shut down completely.
Sharply declining refinery demand for crude oil was a key driver in the historic collapse in near-term futures prices for WTI at Cushing earlier this week. With stay-at-home directives in place in most of the industrialized world, U.S. — and global — demand for motor gasoline and jet fuel has plummeted to levels not seen in decades. These changes in refined-products demand, which may continue for months, already are having significant impacts on U.S. refineries — not just in how much crude oil they need but in operators’ decisions on whether to adjust their crude slates and ramp down or alter their operations. Their urgent challenge is to revise their yields to something close to the appropriate volumes of gasoline, diesel and jet fuel. Today, we begin a blog series on the U.S. refining sector and what refiners can — and can’t — do to adapt to these extraordinary times.
The collapse in crude oil prices and COVID-19’s very negative effects on global gasoline, jet fuel and diesel demand are putting an unprecedented squeeze on U.S. refiners. Even before the initial coronavirus outbreak in Wuhan, China, started to grab headlines around New Year’s Day, refineries had already been incentivized to shift their refined products output toward diesel, which can be used to help make IMO 2020-compliant low-sulfur bunker. Now, with the COVID-19 pandemic spreading to Europe and North America and stifling consumer transportation fuel demand, the price signals are even stronger, pushing refineries to do everything they can to minimize their gasoline and jet fuel production and enter what you might call “max diesel mode.” Today, we discuss how there are challenges and limits to what they can do, and a number of refineries may need to shut down due to lower demand, at least temporarily.
Over the weekend, PBF Energy closed on its acquisition of Shell’s Martinez, CA, refinery, marking the first completed U.S. refinery transaction of 2020. The closure of that deal may seem unremarkable, but it’s rare for more than two to three transactions involving individual refineries to take place in the U.S. in a given year, and there are as many as eight other refineries on the market. These include two each in the Philadelphia area, the Midcontinent and the Rockies, and one each in Washington state and Alaska. Why are so many refineries on the block? Today, we continue our series with a look at the facilities said to be on the market in PADDs 4 and 5.
It was reported earlier this month that Shell is seeking a buyer for its Washington state refinery, which is located just outside Seattle in Anacortes. That brings to eight the number of U.S. refineries said to be up for sale by a variety of sellers, from integrated major oil companies to independent merchant refiners — plus another refinery that is already under contract. That’s an unusually high number — refineries rarely change hands in the U.S. and when they do, it’s typically for large sums of money to sophisticated and vertically integrated buyers. Today, we discuss the facilities on the block in the East Coast and Mid-Continent regions and the market drivers that could be impacting the decisions of potential buyers and sellers.
Texas consumes far more diesel fuel than any other state and almost as much gasoline as car-crazy California, which also has 10 million more people. The long-distance distribution of refined products within the Lone Star State is handled largely by tanker trucks, but in the past couple of years, midstream companies have been adding a lot of new refined products pipeline capacity, not just to help deliver diesel and gasoline within Texas — including the diesel-hungry Permian Basin — but also to move motor fuels to the Mexican border for export. And more diesel and gasoline pipe capacity is on the way. Today, we discuss the new and expanded refined products pipelines criss-crossing Texas.