Sustainable aviation fuel and renewable diesel don’t make as many headlines as other renewables, but they are critical to the transition away from fossil fuels.
Jordan Godwin, OPIS Director of Renewable Fuels, and Denton Cinquegrana, OPIS Chief Oil Analyst, examine the market and regulatory forces bringing these fuels front and center. Watch the excerpt of their conversation from Barron’s Live:
Spanish energy company Repsol is preparing to start production of sustainable aviation fuel (SAF) with a new 250,000 metric tons/year biofuel plant at its Cartagena industrial complex in the southeast of Spain.
Tomas Malango and Oliver Fernandez, Repsol’s Renewable Fuels and International Aviation directors, spoke on the sidelines of the IATA’s World Sustainability Symposium in Madrid in early October about the company’s plans to meet growing demand for SAF.
OPIS: So Cartagena is almost ready to produce SAF?
Malango: Yes. We’re in the commissioning stage, and our goal is to kick-start [the biofuel plant] before the end of the year.
OPIS: Is it going to produce both SAF and HVO (renewable diesel)?
Malango: Yes. It’s a plant that can operate in 100% SAF mode, producing around 200,000 metric tons/year, in 100% HVO mode around 250,000 mt/year, or in a mixed mode of both HVO and SAF.
OPIS: At current prices, what share of production would you allocate to SAF versus HVO?
Malango: I think it’s not about price, but about demand. Our plan is to start with higher HVO production. Then, as SAF demand develops, the plant would end up producing only SAF by the end of the decade. We’ll move with the market; if it demands more SAF, we’ll raise output faster.
We can’t deploy French fries restaurants to produce more SAF.
OPIS: Will your SAF market be Spain and Portugal, or will you be exporting as well?
Malango: We’ll be able to sell SAF as far as clients are willing to pay for it; it’s a strictly commercial issue. The product can travel; there is an existing infrastructure in place.
Fernandez: To provide some context, if the 2% SAF mandate started today, those 200,000 mt/year alone would be more than enough to meet the SAF demand of Spain and Portugal and have a production surplus. This surplus gives you optionality. There are airlines that want to go beyond the 2% mandate and are in the voluntary SAF market. The plant will be able to meet both mandated and voluntary SAF demand. Where? In Spain and Portugal. And then, depending on market dynamics, we might be able to go to Europe.
OPIS: What’s your forecast for the used cooking oil (UCO) market as a feedstock? Do you have any concerns about supply?
Malango: Waste is an anomalous type of commodity because you cannot increase waste production. Usually, when there is an increase in demand for a given commodity, supply rises to balance the price. With UCO, you have an existing waste that is mostly yet to be collected. In Spain, only 4% of domestic UCO is collected [at present]. We have a project to collect oils from the domestic sector at fuel stations, and we are working to build supply chains that are closer to Spain. But the UCO market is what it is and we have to go fetch it wherever it is. We can’t deploy French fries restaurants to produce more SAF. [UCO supply] will peak at some point.
OPIS: So now, in order to kick-start SAF production, have you had to source UCO from Asia?
Malango: From everywhere. We have national supply, European supply and Asian supply. We have a combination of supply contracts and our own supply chains that are being developed region by region.
OPIS: And Repsol is also planning a biofuel project in Puertollano, Spain. Is that going to produce SAF as well?
Malango: Puertollano will produce 100% HVO. This will allow us to free up Cartagena to produce SAF. Cartagena will start combining HVO and SAF production. When we have Puertollano running, we will be able to switch Cartagena to full SAF production by late 2025 or early 2026, depending on how the SAF market develops.
OPIS: Some companies are selling SAF indexed to oil prices. Is that the case for Repsol as well?
Malango: You have three ways of selling SAF in terms of price formula. One is fossil fuel indexation plus a green premium. Another one is the so-called “cost plus,” the cost of production plus a margin. The third one is an indexation to SAF market benchmarks, which take into account feedstock costs among other things. We work with all three formulas. It’s more a question of how the customer wants to handle the potential price volatility.
Fernandez: The airline industry has been using jet fuel benchmarks for many years. They have been buyers of a single product for decades. I believe airline reticence is not caused by switching to a SAF benchmark, but because they don’t have the capabilities to change, because they’ve been doing it that way their whole lives. It’s a market that is changing entirely, and so you have to sit down with them and explain that this is a new product with different dynamics and feedstocks, that it would be reasonable that, if you’re buying potatoes, you’re not indexing it to lemons, but to potatoes. There is some initial shock, but mainly because of that habit of using A1 jet fuel benchmarks.
Malango: But, in the end, it is sold the way the customer wants.
OPIS: And is it being sold via annual contracts with airlines?
Fernandez: The market is in its birthing phase, until a few weeks ago there was no regulatory clarity. The mandates were announced on Sept. 13. Until then, there were just people demanding SAF on the voluntary market with all types of contracts. We signed a pluriannual contract with Ryanair in May, and there are other contracts that are shorter.
But, above all, what producers and airlines want is to have regulatory clarity. You won’t sign any long-term contracts if you don’t know what the mandate is, what the obligations are, who bears the obligations, what is the obligation based on. Is it by airport? Annually? Quarterly? Weekly? Is it on a European or national basis?
There are many question marks. The path is not clear yet. We had a meeting with the MEP responsible for the law a few weeks ago, and he said that there are some details that aren’t likely to be clarified until June next year.
Today, airlines are saying “we need, we need, we need the product.” Perfect. From our side, we took the risk, our board green-lighted this investment four years ago, when the regulatory framework was even worse. The fact is that now we have it, at least to cover Spain and Portugal, so we are glad for airlines to come and see what contract formula they want, in terms of length and price indexation.
–Editing by Rob Sheridan, rsheridan@opisnet.com
The energy transition is forcing companies to come up with new products and systems to reduce carbon emissions. Within the transport sector, sustainable fuels are seen as a key decarbonization solution, with major energy companies pledging to increase production.
Refiners, marketers, retailers, pipeline operators and others across the gasoline supply chain may be impacted in the spring and summer of 2023 by a lower Reid Vapor Pressure (RVP) specification for CBOB in Midwest states.
After four years of the Trump administration’s often-chaotic approach to the Renewable Fuel Standard (RFS), many in the biofuels industry were hoping President Joe Biden would bring a level of stability and support to the program.
Each year, attendees of OPIS’s RFS, RINs & Biofuels Forum come to the event looking for answers about biofuel markets and the government’s approach to the Renewable Fuel Standard (RFS) program.
Be on the lookout for some befuddled refining analysts and disappointed investors as public refiners disclose their first quarter earnings in the next 30 days.
On Jan. 1, the U.S. Environmental Protection Agency (EPA) Fuels Regulatory Streamlining Rule went into effect, and while some impacts are already being felt in east of the Rockies markets, others are on the horizon as gasoline markets continue to transition to summer gasoline specifications.
With this regulatory shift, test methods for reformulated gasoline (RFG) – the gasoline made by blending RBOB with ethanol – were simplified. Instead of the previous “complex model,” in which rigid “VOC-controlled” gasoline parameters had to be met during summer Reid Vapor Pressure (RVP) months, RBOB testing now is focused primarily on benzene, sulfur and RVP specifications.
The use of RFG accounts for roughly one third of gasoline sold in the U.S., according to IHS Markit’s PADD 1 Downstream Profile for January 2021. In PADD1 (the U.S. East Coast), it is required in Connecticut, Delaware, Massachusetts, New Jersey, Rhode Island, the District of Columbia, and the more populous counties of Maine, Maryland, New Hampshire, New York, Pennsylvania and Virginia. IHS Markit is the parent company of OPIS.
The results of this regulatory shift will affect U.S. Gulf Coast, Midwest and East Coast gasoline markets, with Chicago and some Texas markets using RFG in addition to those East Coast locations.
One of the most prominent changes is a shift in RVP specifications, with 7.4-lb. RVP as the new limit for summer-grade RFG gasoline, reflected in the summer-grade specifications for the U.S. Gulf Coast, New York Harbor barge and cargo, Buckeye Pipeline, Linden Junction, Boston cargo and Chicago gasoline spot markets.
More broadly, this shift is expected to make RBOB easier to manufacture at refineries, import terminals and blending hubs. Likewise, the new regulations may also make recertification of gasoline easier.
With this, product flows in the eastern half of the U.S. have begun to see impacts. Colonial Pipeline, a major transporter of gasoline originating in Pasadena, Texas, and terminating in Linden, New Jersey, has not adjusted the product grades being shipped, including regular and premium grades of RBOB, CBOB and conventional gasoline, and those grades are not being commingled. However, Colonial Pipeline has adjusted summer-grade RVP specifications and will also allow for some regrades: RBOB can be regraded to the same CBOB RVP number, while CBOB will only be regraded to a higher-RVP number.
This streamlining of rules also appears likely to make imports to the U.S. East Coast more attractive. In the past, even when the arb was “open,” there was a risk in sending gasoline to the region, due to the rigid standards which needed to be met. Additionally, because the East Coast has continued to see relatively strong prices, Atlantic Basin shippers have continued to send barrels to the region throughout the COVID-19 pandemic.
Gasoline imports to PADD1 (the U.S. East Coast) have averaged 452,000 b/d in the first 10 weeks of 2021, compared to about 441,000 b/d during the same time frame in 2020, according to the U.S. Energy Information Administration (EIA). That comes even as Renewable Identification Number (RIN) prices jumped sharply higher, with the OPIS Renewable Volume Obligation (RVO) approaching 16cts/gal as of the second week of March, its highest level in the 13-year history of OPIS RINs assessments. Normally, high RINs and RVO costs are a disincentive to imports. Lost production in the U.S. Gulf Coast following freezing temperatures there in mid-February was also appearing to provide an incentive for imports to the U.S. East Coast. The Gulf Coast is a key provider of gasoline to the East Coast.
You need more than just a NYMEX or ICE futures’ screen to keep pace with petroleum prices, based on the first 22 business days of 2021. Crude oil prices sprinted out of the gate in the first full week of the new year, but prices for Renewable Identification Number (RIN) credits, bean oil, and even ethanol occupied much of the downstream fuel limelight in subsequent sessions.
The LPG sector is exploring almost a dozen different pathways to usher in a decarbonized “bioLPG” future, however, commercial and technical hurdles have yet to be overcome to bring volumes to scale, delegates heard at this year’s World LPG Association (WLPGA) “e-LPG Week.”
Produced from renewable and organic feedstock, bioLPG has an identical chemical structure to conventional LPG, though its carbon footprint is up to 80% lower, according to Liquid Gas Europe, the European LPG sector body.
Already available in a number of European countries, in small but steadily growing volumes, bioLPG can be blended as drop-in fuel and used in existing infrastructure and appliances, without a change or upgrade of equipment.
Current bioLPG output amounts to about 180,000 tons worldwide, according to George Webb, the CEO of Liquid Gas UK, who expects “another 100,000 tons” to be added over the next few years. About half of volumes are used as process fuel.
A Plethora of Pathways
BioLPG can be produced in numerous ways, typically as by-product, using different feedstocks and processes.
Current processes use about 60% waste and residue materials as feedstock and 40% renewable vegetable oils (such as jatropha, algae, rapeseed, palm, soy), with a plethora of production pathways being pursued. Waste includes residues from food processing.
Organic feedstocks have to meet sustainability criteria, and first-generation crop-based feedstocks will be phased out over time, to be replaced by waste and residue materials, according to Liquid Gas Europe. The European Union’s current 7% cap on crop-based biofuels is to be lowered in increments to 3.8% by 2030.
Biorefining has the highest “technology readiness level” and hence already operates at commercial scale. It involves the hydrogenation or hydrotreating of “lipids” — i.e. organic compounds that are fatty acids or their derivatives, such as vegetable oils, biomass-derived oils or animal fats.
Hydrotreated vegetable oil (HVO) or hydrotreated esters and fatty acids (HEFA) are used to produce renewable diesel or sustainable aviation fuel. Waste ‘off-gases’ containing propane occur as by-product. Every ton of renewable diesel/kerosene yields about 50 to 80 kilograms (5-8%) of bioLPG from this purified off-gas stream.
Other advanced options are gasification through the “Fischer-Tropsch” process, which converts carbon monoxide and hydrogen into liquid fuels; gasification to methanol and subsequent methanol-to-gasoline conversion; pyrolysis of biomass; and the methanation of syngas from biomass gasification.
Processes that have yet to make progress are fermentation-to-LPG, alcohol-to-jet, the conversion of biogas/biomethane (oligomerization), glycerin-to-propane, power-to-x and bio-synthesis. The bioLPG cut varies by process, with a few – oligomerization, glycerin-to-propane, biosynthesis – yielding 100% of propane.
“We are probably going to need all of them, at various different places in the world, at various different times, depending on the feedstock, to be able to meet our full potential as an LPG industry,” said Rebecca Groen, sustainable fuels director at family-owned SHV Energy, who outlined the various options.
A Drop-in Solution
SHV Energy also sees an opportunity in converting biogas and industrial waste streams into fuel-grade renewable dimethyl ether (rDME).
“It is the closest drop-in solution to LPG that is available today,” according to SHV Energy’s Mrs Groen, who also represents the International DME Association. “Whilst we do focus on the alternative routes to bioLPG, we need also some opportunities right now to show that pathway. And rDME is one of those very easily achievable, with production technologies available today.”
rDME can be produced from manure, municipal solid waste, biomass and intermediates (biogas/renewable methanol). It is very similar but not identical to LPG, hence can be used blended or pure, with limited modifications to existing LPG infrastructure and similar environmental benefits. “It’s really the easiest and closest solution and one we think it’s really worth exploring together as an industry,” Mrs Groen said.
Rise in Refineries going Green
A number of refineries are observed adding renewable fuel units, such as HVO, pyrolysis, electrolysis, waste gasification, while the conversion of biogas and unconventional lipids (jatropha, algae or even sewage sludge) also draws interest.
Refineries fully switching to renewables tend to be small, uncompetitive or unviable, “usually with a serious handful of government money to do that,” according to Eric Johnson, managing director at Swiss Atlantic Consulting.
“Progress is being made, but it is bumpier than the headlines suggest, and there are considerable risks,” he said. “But the risks of doing nothing are even greater.”
Not all process technologies offering carbon savings are new – some are “resurrected,” and the odd project firm is being “revived” that had gone bust in the past.
Focus on Efficiency, Alongside Carbon Footprint
Mr Johnson’s view that the path to carbon neutrality “isn’t just about renewables, it is also about efficiency” resounded in the words of Chris Smith, managing director at start-up G-volution.
The firm’s dual-fuel technology allows clean fuel types to combust in diesel engines, including bioLPG, which he sees as “very cost-effective, it’s very green, but most of all it can be applied in lots of places.” He mentioned solid-oxide fuel cells run on bioLPG as another option.
“I feel this combination of a clean fuel and an efficient conversion into electricity has tremendous value in a world that is slightly focused on something which is so expensive and impractical as hydrogen, in the medium term,” Mr Smith said. “A lot of people talk about hydrogen. It has got everybody’s attention, but those of us who know the physics of it understand the challenges.”
Assessing the Economics
Walt Hart, vice president and chief strategist for global NGLs at IHS Markit, the parent company of OPIS, was weighing bioLPG economics. “So, at the moment, the prospects of bioLPG depend on the prospects for renewable diesel,” he said at the e-LPG Week event. “There are other processes that could technically make it, but the economics aren’t necessarily supportive.”
“If you did go through the trouble to put up a process that would convert some cheap bio-feed to something else, it’s likely that you would make other liquids – maybe chemicals, maybe other fuels, rather than making bioLPG,” according to Mr Hart.
Faster decarbonization efforts in Europe could pressure prices if LPG from traditional sources is pushed onto the global market. “If you have a lot of LPG going into the market very quickly, it’s more expedient to build petrochemical processes than to build all the infrastructure for residential or commercial markets,” Mr Hart said.
However, he also considered that lower oil product demand in the 2030-40s could reduce supplies of naphtha, on which about 40% of global ethylene output depends at present. “If your naphtha availability starts to get a little bit tight, then you’re looking for other feedstocks, and LPG could really fit the bill on that,” Mr Hart said.
“It seems the world has to keep one foot on the accelerator (r[enewable]LPG) and one foot on the brake (LPG),” WLPGA director David Tyler concluded. “Isn’t there an argument then to channel fossil LPG into developing countries, to displace wood as a cooking fuel, while the developed world goes down the rLPG route?”