On January 1, 2020 the International Maritime Organization (IMO) implemented new fuel standards for oil-powered vessels, except those equipped with exhaust scrubbers to remove pollutants. In the absence of a scrubber, the IMO 2020 rule stipulates that ships' bunkers contain less than 0.5% sulfur. Using a scrubber allows the vessel to burn cheaper high-sulfur fuel. Last March, a shipowner’s estimated $2.5 million scrubber investment for a 2-MMbbl Very Large Crude Carrier (VLCC) would take just over three years to recover, based on average fuel prices during the first quarter of 2019. This year, barely a month after the new regulation came into force, the payback period has shortened dramatically, to less than a year, though the coronavirus’s effect on shipping demand and fuel prices, among other factors, could again put payout timing at risk. Today, we look at changing price spreads between high-sulfur and low-sulfur bunker and the scrubber payback economics that suggest a rosier outlook for vessel owners who invested in scrubber installations, at least for now.
Some shipowners plan to comply with the IMO 2020 deadlines for limiting sulfur in ship emissions by installing scrubber devices to clean the exhaust generated by burning less expensive high-sulfur bunker fuel. For many, this may work out to be more economical, at least in the interim, than using more costly IMO 2020-compliant fuel with sulfur content of no more than 0.5% or converting the vessel to run on an altogether different fuel such as liquefied natural gas. However, narrowing “sulfur spreads” this year have put that compliance strategy at risk by tripling the time it would take for shipowners to recoup their scrubber investments. Today, we continue an analysis of the changing economics of scrubber installation in the run-up to IMO 2020.
Last year, the impending implementation of International Maritime Organization’s rule mandating the use of lower-sulfur marine fuels starting January 1, 2020, widened the price spread between rule-compliant 0.5%-sulfur bunker and the 3.5%-sulfur marine fuel that has been a shipping industry mainstay. Traders’ thinking was that demand for high-sulfur bunker would evaporate in the run-up to IMO 2020, as the new rule is known. But since early January, the spread between low- and high-sulfur fuel at the Gulf Coast has narrowed from nearly $11/bbl to less than $2/bbl. The culprit is a shortage of heavy-sour crude caused by a number of factors. Today, we begin a two-part series on low-sulfur vs. high-sulfur fuel and crude values as IMO 2020 approaches.
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.
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.
U.S. exports of diesel and other distillates averaged 1.2 million barrels/day (MMb/d) in 2016, more than eight times their 2005 level and up slightly from 2015, another in a series of record-busting years for distillate exports. So far, 2017 looks like another winner. This year, though, a lot more distillate is being shipped south from Gulf Coast marine terminals to nearby Central America and South America, and less is being floated across the Atlantic to Western Europe. Today we consider recent trends in U.S. distillate exports and the significance of the export market to U.S. refiners.
New International Maritime Organization rules slashing allowable sulfur content in bunker fuels come January 2020 are expected to be a boon to complex refineries with coking units that can break residual high-sulfur fuel oil (HSFO) into low-sulfur middle distillates and other high-value products. The IMO rules also are expected to undermine the already shaky economics of many simpler refineries that don’t have cokers and are therefore left with a lot of residual HSFO. Today we conclude our blog series on the far-reaching effects of the new cap on bunker fuel sulfur content with a look at how the IMO rules will create winners and losers among refineries, and improve diesel refining margins.
Much tougher rules governing emissions from ships plying international waters soon will force wrenching change on the energy industry. Demand for high-sulfur fuel oil is expected to plummet; ditto for HSFO prices. Demand for low-sulfur distillates from the shipping industry will rise sharply, putting upward pressure on prices for marine gas oil, marine diesel oil and ultra-low-sulfur diesel. These demand and pricing shifts, in turn, will have a number of significant effects on refiners. Today we continue our series on the far-reaching effects of the International Maritime Organization’s (IMO) mandate to slash emissions from tens of thousands of ships starting in January 2020.
A new international rule slashing allowable sulfur content in the marine fuel or “bunker” market will have profound effects on global demand for high sulfur fuel oil and low-sulfur middle distillates—and with that, major impacts on the price of those products, the demand for various types of crude, and the need for refinery upgrades. What we have in the making here is a refining-sector shake-up that will extend well into the 2020s. Today we begin a series on the rippling effects of the International Maritime Organization’s (IMO) mandate that, starting in January 2020, all vessels involved in international trade use marine fuel with sulfur content of 0.5% or less.
The agreement by OPEC and several non-OPEC members to cut crude oil production by a total of 1.8 million barrels a day (MMb/d), which caused a rise in crude prices, kicked in on January 1. Now, more than three weeks in, many in the market remain skeptical that the deal will hold, and are on the lookout for the slightest hint that parties to the agreement may be—for lack of a kinder word—cheating. In today’s blog, “Won’t Get Fooled Again—Monitoring Compliance With The OPEC/NOPEC Deal To Cut Production,” we recap the agreement’s terms, examine how participating producers might try to skirt the rules, and discuss ways to check that everyone is acting on the up and up.
The five refineries in the U.S. Pacific Northwest (PNW) performed better in 2016 than rivals on the East Coast for two main reasons. First, the changing pattern of North American crude supply has worked to their advantage. Faced with the threat of dwindling mainstay crude supplies from Alaska, refiners in Washington State replaced 22% of their slate with North Dakota Bakken crude moved in by rail. They have also enjoyed advantaged access to discounted crude supplies from Western Canada. Second, PNW refiners face less competition for refined product customers than rivals on the East and Gulf coasts, meaning they have a captive market that often translates to higher margins. Today we review performance and prospects for PNW refineries.
Shipping companies now know that within three years all vessels involved in international trade will be required to use fuel with a sulfur content of 0.5% or less—an aggressive standard, considering that in most of the world today, ships are currently allowed to use heavy fuel oil (HFO) bunker fuel with up to 3.5% sulfur. This is a big deal. Ships now consume about half of the world’s residual-based heavy fuel oil, but starting in January 2020 they can’t—at least in HFO’s current form. How will the global fuels market react to a change that would theoretically eliminate roughly half the demand for residual fuels? How will ship owners comply with the rule? What are their options? Today we discuss the much-lower cap on sulfur in bunker fuels approved by the International Marine Organization, and what it means for shippers and refineries.
Each winter, New York spot prices for gasoline and diesel spike higher than spot prices in Chicago, opening a seasonal arbitrage opportunity for Midwest refineries and motor fuel marketers—if only they could move more product east from Petroleum Administration for Defense District (PADD) 2 to the East Coast’s PADD 1. Midstream companies have taken note, and have been adding eastbound refined product pipeline capacity in Ohio and Pennsylvania. So far the aim has been to move gasoline and diesel as far east as central Pennsylvania, but the longer-term goal seems to Philadelphia, which ironically is the center of East Coast refining. Today we look at the ongoing shift in market territories claimed and sought by gasoline and diesel refineries and marketers in PADDs 1 and 2.
Mexico’s consumption of motor fuels is rising, its production of gasoline and diesel continues to fall, and U.S. refineries and midstream companies are racing to fill the widening gap. The export volumes are impressive: deliveries of finished motor gasoline from the U.S. to Mexico averaged 328 Mb/d in the third quarter of 2016, up 41% from the same period last year, and exports of low-sulfur diesel were up 29% to 194 Mb/d. And there’s good reason to believe that U.S.-to-Mexico volumes will keep growing. Today we look at recent trends in gasoline and diesel production and consumption south of the border, and at ongoing efforts to enable more U.S.-sourced gasoline and diesel to reach key Mexican markets by rail and pipeline.