The countdown clock to January 1, 2020 — Implementation Day for the IMO 2020 rule on low-sulfur marine fuel — is ticking, and while that date may still seem far away, it is decidedly not. The impending switch from 3.5%-sulfur fuel oil to marine fuel with sulfur content no higher than 0.5% will affect a broad swath of the energy sector worldwide, not to mention consumers of diesel and other low-sulfur distillates that will be in much higher demand by this time next year as the run-up to IMO 2020 kicks into high gear. Already, complex and simple refineries alike are evaluating changes to their crude slates and planning to add equipment that will enable them to produce more high-value distillate and less “bottom-of-the-barrel” residual fuel oil, the source of high-sulfur marine fuel. U.S. midstream companies are gearing up to export more light, sweet crude from the Permian and other shale and tight-oil plays to simple refineries that will no longer be able to get by refining heavy, sour crudes. Marine-fuel suppliers are testing various blends to see which might produce IMO 2020-compliant fuel at the lowest cost. As for ship owners, they’re preparing for topsy-turvy fuel prices in late 2019 and 2020 as this wrenching change plays out. Today, we consider key market participants’ latest thinking on the likely effects of the new rule for low-sulfur marine fuel.
While crude oil producers in the prolific Permian Basin are living out a Shale Revolution, the Midcontinent region of the U.S. is having a Refining Renaissance. Crude takeaway constraints, mainly due to insufficient pipeline capacity, are driving the prices of crude in Western Canada and West Texas to attractive lows against the WTI NYMEX benchmark for crude at the Cushing, OK, hub. Cheaper oil can contribute to bigger margins for refiners, who are supplying increasing volumes into a retail market that’s selling gasoline at the highest prices in four years. What will happen if the refiners don’t rein in their runs? Today, we’ll explore the implications of record-high run rates in the U.S. refining industry.
The Caribbean is strategically located at the crossroads of international trade routes between the Northern and Southern hemispheres, as well as the Atlantic and Pacific oceans. It has traditionally attracted oil trading, blending, and refining activity to meet the needs of local and international markets. Lately, the meltdown of Venezuelan national oil company Petróleos de Venezuela SA (PDVSA) — previously a dominant player in the region — has left refineries and storage terminals underutilized and starved of investment. U.S. Gulf Coast refineries have partially filled the gap by increasing product exports to the region, but an opportunity now exists for private investment to fill the refining and storage void left by PDVSA, and also to meet new demand for low-sulfur bunker fuel arising from stricter International Maritime Organization shipping regulations, which will come into effect in January 2020. Today, we review the impact of the PDVSA meltdown and new investment projects being pursued.
Mexican demand for U.S.-sourced refined products continues to increase, but Mexico lacks the infrastructure required to efficiently import, store and distribute large volumes of gasoline and diesel. That has spurred the rapid build-out of new port and rail terminals, new pipelines and new storage capacity on both sides of the U.S.-Mexico border. At the same time, Mexico’s state-owned energy companies are gradually opening access to their existing refined-products pipeline and storage networks — which helps a little, but not enough. Today, we discuss the latest round of midstream projects tied to U.S. exports of motor and jet fuels to its southern neighbor.
The planned implementation of the International Maritime Organization’s rule slashing allowable sulfur-dioxide emissions from ocean-going ships on January 1, 2020, would create significant demand for 0.5%-sulfur marine fuel — a refined product that few refiners produce today. That could present a big challenge to the global refining sector, which will be called upon to produce marine fuel that complies with “IMO 2020,” as the rule is commonly known. But refiners have stepped up before, and if the IMO 2020 mandate proves to be unachievable and would put global commerce at risk, there could be ways to deal with it — including exemptions or implementation delays. In any case, the move toward much cleaner bunker fuel will be a boon to complex refineries along the U.S. Gulf Coast and elsewhere that can break down bottom-of-the-barrel “residual” fuel oil into feedstocks for gasoline, diesel and other high-value products. Today, we continue our analysis of IMO 2020 and its effects.
Drilling and completion activity in the Permian Basin doesn’t only produce vast quantities of energy, it consumes a lot of energy too, mostly in the form of diesel fuel to power the trucks, drilling rigs, fracturing pumps, compressors and other equipment needed to keep the oil patch humming. And while refineries within or near the Permian meet a portion of the region’s needs, rising demand for diesel there is spurring the development of new infrastructure — and the repurposing of existing assets — to bring additional fuel into the Permian from refineries along the Gulf Coast. Today, we discuss efforts to move more diesel to the oil fields of West Texas.
Shipowners and refiners are struggling with how to prepare for January 1, 2020, when all vessels involved in international trade will be required to meet significantly stricter limits on emissions of sulfur oxides (SOx), either by using fuel with a sulfur content of less than 0.5% or by “scrubbing” the exhaust of ship engines when using the much higher-sulfur bunker fuel that most ships now rely on. The International Maritime Organization’s (IMO) new sulfur rule isn’t a minor tweak. It’s a game changer that already is causing widening spreads on the futures market between 3.5%-sulfur heavy fuel oil (HFO) — the traditional global bunker fuel — and rule-compliant low-sulfur distillates. The rule also promises to be a boon to complex Gulf Coast and other refineries that can break down residual-based HFO into higher-value, lower-sulfur distillates. Today, we begin a new series on how shipowners, refiners and the markets for HFO and low-sulfur marine fuel are responding (or not) to the coming change in global bunker requirements.
For a couple of years now, Buckeye Partners has been working to advance a controversial plan to reverse the western half of its Laurel refined-products pipeline in Pennsylvania to allow motor gasoline, diesel and jet fuel to flow east from Midwest refineries into the central part of the Keystone State. Some East Coast refineries that have relied on Laurel for 60 years to pipe their refined products as far west as Pittsburgh have been fighting Buckeye’s plan tooth and nail, arguing that it would hurt their businesses and hurt competition in western Pennsylvania gas and diesel markets — and refined-product retailers in the Pittsburgh area agree. Now, after a state administrative law judge’s recommendation that Pennsylvania regulators reject Buckeye’s plan, Buckeye has proposed an alternative: making the western half of the Laurel Pipeline bi-directional, which would allow both eastbound and westbound flows. Today, we consider the latest plan for an important refined-products pipe and how it may affect Mid-Atlantic and Midwest refineries.
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.