ExxonMobil earlier this month told analysts in New York that the company expects to add a total of 400 Mb/d of capacity to its three giant Gulf Coast refineries by 2025. Exxon plans to upgrade existing refineries in Houston (Baytown) and Baton Rouge, LA, to increase production of higher-value products and to add a new crude distillation unit to its 362-Mb/d Beaumont, TX, plant after 2020. A final investment decision on the Beaumont expansion — which reportedly would double the refinery’s throughput capacity and make it the largest refinery in the U.S. — is expected later this year and follows a $6 billion investment by Exxon to triple crude output from its Permian Basin production assets in West Texas. Today, we discuss the existing Beaumont operation, its feedstock sources, and the refined-product demand that supports the plant’s expansion.
When Philadelphia Energy Solutions (PES), owner of the East Coast’s largest refinery, recently announced it was seeking Chapter 11 bankruptcy protection, it begged a question: What happened? The answer requires a look back at the company’s original vision — namely, to capture the upside of the Shale Revolution by processing price-advantaged light, sweet crude oil produced in the U.S. — as well as a review of market developments that undermined its plan. Today, we look at the factors that drove PES’s hopes and why, in the end, they weren’t realized.
Mexico continues to open up its refined-products sector to competition, and refinery troubles at government-owned Pemex are providing U.S. refiners and motor-fuel marketers with a golden opportunity to export increasing volumes of gasoline and diesel south of the border. But transporting all those refined products to Mexican population centers and distributing them to thousands of service stations requires port and rail terminals, pipelines and storage, and Pemex has been slow in relinquishing control of its infrastructure. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time looking at more port and rail-related projects and at existing and planned pipelines.
Rockies refineries have enjoyed higher margins than their counterparts anywhere else in the U.S. except California over the past four years, despite being typically smaller and less sophisticated plants. Attractive margins resulted in new investment by their owners — concentrating on the flexibility to process different crude types rather than just boosting capacity — because regional product demand is relatively stagnant. Today, we describe how some of those investments have paid off handsomely so far while others aren’t looking so savvy.
The opening of Mexico’s refined-products sector to competition after 80 years of Pemex monopoly is spurring the development of new motor fuel-related distribution infrastructure on both sides of the U.S.-Mexico border. A number of these pipelines, rail loading/unloading facilities, storage and other projects aren’t advancing as quickly as their developers may have hoped — replacing the old order with the new is taking time. But the need for new infrastructure is evident. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time focusing on rail-related projects.
Refiners in the five Rocky Mountain states that make up the U.S. Energy Information Administration’s Petroleum Administration for Defense District 4 — or PADD 4 — enjoy higher margins than their counterparts in every other part of the country except California. Quarterly crack spreads for domestic crude in PADD 4 averaged $25/bbl between 2014 and 2017, while those for Canadian crude averaged $31/bbl. Today, we explain that these lofty cracks reflect an abundance of crude — both from indigenous Rockies production and Canadian and North Dakota supplies passing through the region — as well as higher-than-average diesel and gasoline prices.
U.S. exports of motor gasoline and diesel to Mexico are up 60% from two years ago, and the ongoing liberalization of Mexican energy markets is allowing players other than state-owned Pemex to become involved in motor fuel distribution and retailing there. But there’s a catch. The port, pipeline, rail and storage infrastructure currently in place to receive U.S.-sourced gasoline and diesel and transport it within Mexico is inefficient and stressed. Further, Pemex owns or controls most of these fuel logistics assets and has been slow to make them available to others. Today, we continue our series on efforts to facilitate the transportation of motor fuels to and within the U.S.’s southern neighbor.
Falling production of motor gasoline, diesel and other refined products at Mexico’s aging refineries has created a south-of-the-border supply void that U.S. refiners and refined-products marketers and shippers are all too eager to fill. At the same time, the ongoing liberalization of Mexican energy markets is finally allowing players other than state-owned Petróleos Mexicános (Pemex) to become involved in motor-fuel distribution and retailing. The results of all this? U.S. exports of gasoline and diesel to Mexico are up 60% from two years ago, and U.S. companies are scrambling to develop or acquire the infrastructure needed to deliver refined products to Mexican consumers. Today, we begin a new series on the increasing role of U.S. companies in supplying, distributing and retailing motor fuels in Mexico, and on the new transportation and terminalling infrastructure being built to support that growth.
U.S. inventories of distillate — especially ultra-low-sulfur diesel (ULSD) and heating oil — are at their lowest pre-winter level in three years after falling during the summer months for the first time since inventory records started being measured in 1982. Rising diesel exports are one culprit; another is the shutdown of a number of Gulf Coast refineries during and immediately after Hurricane Harvey. The good news is that distillate prices have been increasing, as have the margins for refining crude oil into distillate — both encouraging refineries to ramp up their diesel/heating oil production. Today, we look at recent developments in the distillate market and what they may mean for diesel and heating oil prices this winter.
Over the past few years, rising production in the Canadian oil sands and U.S. shale plays such as the Bakken, Permian and Eagle Ford has given refiners new options for sourcing their crude, causing changes in oil pipeline utilization and prompting the development of new pipelines — or the reversal of existing pipes. A prime example of all this is playing out in Memphis, TN, where a Valero Energy refinery will be shifting from mostly U.S. Gulf Coast-sourced light crude to light crude that will flow in on the new Diamond Pipeline from the Cushing, OK, crude storage hub. Valero’s change in crude sourcing will be yet another blow to the 1.2-MMb/d Capline Pipeline, which for decades has moved crude north from the Gulf Coast to Patoka, IL, and other points along the way, including western Tennessee. Today, we look at the thinking and economics behind Valero’s plan and at the latest news on Capline.
California’s 12 remaining refineries don’t feel much love from their native state. The refinery fleet is particularly sophisticated — capable of refining mostly heavy and sour crude oil into the ultra-clean transportation fuels that state rules require. But state regulators seem to treat refiners like unwanted guests, to the point that rules have been put in place to actively encourage the shift from petroleum-based fuels to lower-carbon alternatives. The reward for refiners’ pain comes in the form of higher refining margins — particularly during unplanned outages. Today we weigh the rewards of higher gasoline and diesel prices today against a questionable future for refining in the Golden State tomorrow.
California refiners are under siege. State regulators seem to view crude oil refining as a nasty habit that needs to be broken. There’s an important catch, though: car-happy California is not only the nation’s largest consumer of gasoline — and second to Texas in diesel use — it allows only special, superclean blends to be sold within its boundaries. And California’s 12 remaining refineries need to meet tougher emission standards, too, making it difficult for them to expand their business or even modernize their plants. Today we discuss the irony that sophisticated refineries producing the cleanest fuels in the U.S. are faced with a shrinking market and no real hope of expansion.
Over the past five years, the price differential between regular and premium gasoline has been widening steadily. According to the Energy Information Administration (EIA), as of July 2017 the premium -vs.-regular differential reached $0.53/gallon — more than double the differential in 2012. This has produced cringe-worthy experiences at the pump for consumers requiring the premium grade and an incentive for refiners to optimize the gasoline pool. Consequently, refiners have been making operational adjustments and capital investments to squeeze additional high-octane components out of their feedstocks. Today we examine the premium-regular gasoline differential, provide a primer on gasoline blendstocks and octane levels, and discuss some contributing factors to the widening divide between the pump prices of 87- and 93-octane gasoline.
Worldwide, refiners expect to add significant capacity over the next five years, mostly in the Middle East and the Asia Pacific region. While only a small amount of crude processing capacity additions are expected in the U.S. and Canada, the capacity additions elsewhere could have major product-trade and utilization effects on U.S. refiners — especially in PADD 1 (East Coast). Today we analyze expected near-term refinery capacity additions, global demand projections, and potential effects in the U.S.
Refiners in the Midwest and in the Mid-Atlantic states have each experienced good times and bad, both before the Shale Era and more recently. Lately, though, fortune has been smiling on the owners of midwestern refineries, a number of which have been expanded and reconfigured to run cheaper heavy crude from western Canada — changes that have put them at a competitive advantage to East Coast refineries running more expensive light crudes. Now, a proposed refined products pipeline reversal in Pennsylvania would allow more motor fuels to flow east from Petroleum Administration for Defense District (PADD) 2 into markets traditionally dominated by PADD 1 refineries. Today we look at recent developments in Midwest and Mid-Atlantic refining, and at the consequential battle for turf that’s just starting to flare.