Ahead of the European Union’s ambitious proposal to ban the sale of new gasoline and diesel internal combustion (IC) engine vehicles by 2035, the Italian liquefied petroleum gas (LPG) Association is preparing for a key review in 2026. The association, led by president Andrea Arzà, will challenge the EU proposal, focusing on the limitations and pitfalls a complete ban of IC engine vehicles would bring.

Arzà spoke to us in November during the LPG week in Rome, on the association’s initiatives and expectations for the LPG market.

OPIS: How does the Italian Association plan to persuade the European Union to consider its proposals for using more LPG instead of completely banning combustion engine (ICE) vehicles?

Arzà: The EU’s “Fit for 55” plan aims for a 55% cut in emissions by 2030 and climate neutrality by 2050. A key part is banning IC engines, which will have the greatest direct implications for the LPG sector. We believe the EU’s plan overlooks emissions linked the whole life cycle of technology, for example from sourcing and production to utilization as well as end-of-life waste management.

We conducted a study, presented during the LPG Week conference, which introduced a fuel blend for cars using LPG, including bio-propane, along with renewable dimethyl ether (rDME). This combination—20% rDME and 80% propane—adheres to EN 589 standards and showcases a 10% to 15% reduction in emissions compared to traditional gasoline.

Another study from the Polytechnic University of Milan analyzed the entire life cycle of electric and IC engines. Electric engines emit zero emissions while running, but we need to look at the entire life cycle of the electric engine, from production to consumption.

This study found that no energy source guarantees a complete emission cut, even if fully renewable. So, adding 20% renewable LPG cuts emissions by 10%. Scaling up this blend with more renewable product significantly boosts performance. Imagine the impact of an 80% renewable LPG and 20% gas blend on the industry!

We strongly believe that we need cars with IC engines powered by renewable fuels instead of electric cars only. For us the priorities are to have a variety of energy sources, an option of choice, with no competition between the different sectors, as well as performance and efficiency.

OPIS: So, what’s the problem, why can’t I drive my car with a renewable LPG fuel blend?

Arzà: In Italy, we’ve made significant progress, but it’s unfortunate that only a few European countries embrace LPG usage due to cultural differences.

For instance, the LPG market in Poland and Turkey surpasses Italy’s market size. Interestingly, the markets in France and Germany are relatively smaller, but they use LPG. Economically robust countries like Germany are less affected by price increases, yet they use more LPG.

The other challenge is finding enough feedstock to produce the quantity of LPG needed. But that’s part of the process. Italy’s refiner Eni said during LPG Week that it plans to increase production of feedstock from organic sources to produce more renewable fuels, including bio-LPG. In Italy Eni declared that they want to increase biofuel production to more than 5 million metric tons/year by 2030. As a side product, bio-LPG production is expected to be around 200,000 mt/year.

OPIS: What is your outlook for the bio-LPG market?

Arzà: By 2030 we will have 200,000 of bio-LPG just from Eni, but it’s possible that companies like Total or BP could develop the technology needed to also produce bio-LPG.

The size of European bio-LPG supply today is less than 200,000 mt/year. We hope to achieve around 1 million mt/year of bio-LPG supply by 2030. If everyone contributes in a similar manner to Eni, I don’t see any reason why bio-LPG production shouldn’t increase. To achieve this goal, we estimate an investment of around €1.5 billion ($1.7 billion) will be required to establish enough bio-LPG production plants by 2030.

OPIS: With the global push for energy security, could you discuss Italy’s strategic priorities in ensuring a reliable and secure supply chain for LPG, and how the association is involved in these efforts?

Arzà: Our goal is to conserve the size of the industry, create molecules that can be blended into the gasoline stream in a safe manner, with no adverse impact for the end-user, nor for the industry. We want to increase blending fossil fuel products with larger quantities of non-fossil fuel products. This can be challenging but also has advantages, as it conserves existing infrastructure and requires less investment while ensuring safety of users.

OPIS: What is the current state of the LPG market in Italy and Europe in terms of consumption and supply? How are you pushing for more consumption without changing the infrastructure?

Arzà: Presently, the Italian market consumes around 3.5 million mt/year of LPG. 50% is consumed by the automotive sector. The domestic sector consumes 25% and the remainder is used by the industrial and commercial sectors.

We hope to maintain and increase consumption as well as supply. We have different scenarios. On the one hand, there are challenges in increasing consumption due to new technology that decreases demand for fuels like LPG. If I have an engine for production or operation, which needs less product for the same output, it is clear that it will potentially reduce regional or even global consumption. For example, new technology allows us to move less, travel less and need less fuel.

OPIS: What are the advantages for adopting a more widespread use of LPG?

Arzà: The replacement of light and heavy oil derivatives with less polluting alternatives represents a significant advantage for the LPG industry. Eliminating pollutants is imperative in both industrial and domestic applications.

This transition doesn’t necessarily involve an immediate switch to heat pumps or electric cars but could instead include a shift from oil to LPG and subsequently to other equipment. This strategic direction offers us an opportunity to be part of the energy transition and maintain or increase consumption and supply of LPG.

OPIS: Where do you see the LPG market headed?

Arzà: Over the next five years, I anticipate a stable market with consistent consumption at 3.5 million mt/year.

The automotive sector is poised to drive LPG demand, as electric cars remain extremely expensive for many, especially low-income consumers who rely on second-hand cars. In 2023, in Italy the number of cars powered by LPG has grown by 10% compared to 2022. That’s one of the best performances ever. This trend is driven by LPG’s cost advantage—50% cheaper than traditional gasoline—and the cautious attitude of potential buyers that await more affordable electric options.

However, the decision to phase out IC engines has adversely impacted the residual value of older cars for those with limited spending power. But despite these challenges, I anticipate another successful year in 2024, with an estimated 10% growth in demand for LPG.

OPIS: How will you navigate the balance between traditional uses of LPG and emerging trends in the energy sector, such as renewable energy integration, especially as the government wants a “mixed energy resources” approach?

Arzà: Innovation is crucial for survival. Our current focus lies in the automotive sector. The challenge we face is to prepare for the 2026 review, ensuring we’re equipped with solid evidence, consistent supply, and comprehensive studies showcasing the performance of LPG. To achieve this, we need to innovate both in terms of producing new molecules as well as new technology.

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:

Non-governmental organizations (NGOs) are pushing for operators in the European Union who use scrap metal in steel production and clinker substitutes in cement-making to be handed free EU carbon allowances to spur decarbonization.

Clinker is a mix of limestone and minerals that is mixed with other materials to make cement, and the process of converting limestone is a carbon-intensive process. Clinker substitutes are available, however, and can be scaled up if EU policy encourages their use.

An EU Commission expert group on climate change policy composed of NGOs, industry associations and member states has met multiple times during the year to revise directives related to the different mechanisms of the cap-and-trade EU Emissions Trading System.

Representatives of Sandbag, a climate policy nonprofit, the European Environmental Bureau, a network of citizen organizations in the bloc, and the World Wildlife Fund European Policy Office (WWF EPO) said that the directives would be presented in the coming weeks or months to allow additional public consultation. The EU Council and Parliament will then choose whether or not to approve the measures by the end of the year.

Camille Maury, a senior policy officer on industrial decarbonization at WWF EPO, said that the allocation of free allowances, in place since 2005, has delayed the industry’s green transition.

“As steel and cement sectors will continue to receive free permits to pollute until 2034 [when the free allowance system is phased out for the two sectors], now is a crucial time to look at how these freebies are allocated and to whom,” Maury said.

“The EU ETS benchmarks must be revised to finally support circularity [and] improve energy efficiency rather than only carry on financing the incumbents. This [free allocation regulation] revision is an opportunity to translate the ambition of the revised EU ETS, agreed in 2022, and make sure it delivers the most ambitious outcome for the climate.”

Redirecting Free EUAs to Less Carbon-Intensive Steel

Riccardo Nigro, a senior policy officer with the European Environmental Bureau, said the steel benchmark currently rewards carbon-intensive processes involving blast furnaces, lime making, coking and inputs that include virgin iron ore.

Currently, there is no incentive to use scrap metal — and the EU Commission’s proposed reforms do not aim to change that — as free allowances are handed out on the basis of the tonnage of hot metal or direct reduced iron (DRI), said Adrien Assous, the executive director of Sandbag. Steel manufacturers that use more scrap metal as part of their input for flat steel production do not receive more free EUAs, while operators that rely on more virgin iron ore inputs receive large amounts of free EUAs.

“It definitely doesn’t cover scrap and our worry is that Europe, the number one exporter of scrap steel, doesn’t know what to do with all this scrap. We send it to Turkey and instead of that we could reuse it and turn it into flat steel products. That would avoid a lot of carbon emissions,” Assous said.

Assous explained that the EU Commission’s proposed revisions to the current rules disincentivize decarbonization or metal recycling by basing free EUA allocation on steel production processes, not the final steel product itself. Under the current free allocation rules, operators who use scrap metal in their steel manufacturing have to pay more than operators who use virgin iron ores, doing away with the incentive to turn to the less carbon intensive input, Assous noted.

“Free allocation [of permits] is given in proportion not of the steel output but of the most polluting component of steel: hot metal. [Hot metal is] an intermediary state of steelmaking and it’s produced in blast furnaces and uses a lot of coal,” Assous said. “But free allocation is given out per ton of hot metal and not of steel, so we’re trying to [convince the EU] that free allowances should be given per ton of steel [produced] and not of hot metal used.”

In a letter in May 2023 to the EU Commission expert group, Sandbag pushed for the inclusion of scrap steel.

“The use of scrap has indisputable climate benefits, roughly reducing emissions by two tons of carbon dioxide per ton of steel scrap used,” the climate non-profit wrote. “It also saves other scarce resources such as electricity compared to other techniques such as hydrogen [direct reduced iron]. Its use should therefore be encouraged at least as much as other abatement techniques.”

Focusing on the final steel product as opposed to the different processes involved in steelmaking will incentivize decarbonization in the sector and will provide operators who use steel scraps in their business with free EUAs, Sandbag argued.

Nigro remarked that the phasing out of free allowances by 2034 under the EU ETS is an important milestone, with the EU’s carbon border adjustment mechanism (CBAM) fully implemented by then and applying the bloc’s carbon price to
imports. With a decade left for free allowance allocation, Nigro said that steelmaking processes that reduce carbon emissions deserve free allowances.

“We’re…10 years away from [the phaseout of free allocation] and basically we want policy reflecting that there are other production processes that should be given more free allocation,” Nigro said.

Clinker-less Cement as an Alternative

Similarly, cement manufacturers do not receive the same amount of free allowances for using clinker substitutes in cement production.

According to the Alliance for Low-Carbon Cement and Concrete (ALCCC), a group composed of 18 low-carbon cement producers, clinker accounts for more than 90% of the sector’s carbon emissions and clinker in cement in Europe averages
around 75%, higher than the global average of 63%. Revising the current cement benchmarks under the EU ETS to include clinker alternatives would reward operators who use less carbon-intensive processes with free carbon allowances.

“The ongoing review of the allocation rules of free emissions under the ETS is a key opportunity for driving this change…the ALCCC is strongly in favor of updating the existing [cement production] benchmark…The current benchmark, based on clinker, has and will not incentivize clinker substitution,” the group said in a statement in August.

“Clinker is the most polluting component in cement and there isn’t really an incentive to reduce emissions even if there are alternatives to clinker,” Assous said. “The free allocation rules are now going to include more alternatives to clinker and this could possibly go quite a long way – though not fully — to solve the problem.”

The ALCCC has called on the EU to give preference in free allocations to processes with the “greatest mitigation potential” including clinker-lowering technologies and alternative binder technologies that rely on supplementary cementitious material or non-clinker based chemistries.

“In line with the ETS directive, it is important that the new [cement] benchmark is both process- and feedstock-neutral, as such putting the right incentives in place for types of technologies,” the ALCCC said in a July statement.

Joren Verschaeve, a program manager at ECOS, an environmental NGO based in Brussels, and affiliate of the ALCCC, told OPIS that the revisions to the EU ETS regulation would also be a chance to push decarbonization as the CBAM is

“With the rollout of CBAM, at some point the [steel and cement] benchmarks will become irrelevant and there’s this discrepancy because Europe tries to push other markets to have their own emissions trading systems inspired by CBAM,”
Verschaeve said.

–Editing by Anthony Lane,

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,

As Mexican President Andres Manuel Lopez Obrador’s administration begins its final year, doubts are rising over whether the government can do much more to boost state-owned oil company Pemex’s position in the market. 

The Lopez Obrador administration has already exhausted all possible legislative, administrative and regulatory steps to help Pemex increase its market share, a key objective of the president when he took office in 2018, analysts and market participants told OPIS. 

Still, they believe Pemex will continue to expand its market share through attractive commercial strategies that offer favorable terms to marketers and retailers. 

Pemex has been particularly successful in 2023 in regaining market share, largely through its independent fuel marketing subsidiary MGC, which was selected as Pemex’s first strategic customer and provided with maximum bulk fuel discounts across the country.

Pemex Market Share Recovered as Government Restrictions Limited Private ParticipationMGC’s aggressive discounts and credit guarantees have squeezed private competitors and smaller Pemex fuel distributors, a market participant told OPIS.

Other Pemex’s distributors are “doing everything to stay afloat,” and are competing with MGC by transferring all Pemex discounts to their customers, the source said.

Pemex has regained the most market through MGC rather than relying on a few branded distributors, the source added. A market analyst said Pemex also is gaining a foothold in the unbranded market, due to its strategic customer program. 

MGC’s aggressive bulk discounts and 30-day credit are advantages that other companies are hard-pressed to match, he added.

Sources believe the market may already be dominated by a select group of Pemex-branded marketers that have benefitted from the strategic customer discount program and generous credit terms offered by the oil company.

Pemex records show that in December 2022, brand distributors Damora Crane and Lemargo were selling more than the 65,000 b/d of fuel required to become a strategic client. Along with MGC, the companies that month supplied a combined 234,000 b/d of fuel.

“Pemex granted them too much power,” a source said, adding that “these companies wield significant negotiating power, even with Pemex.”

Market participants also said they believe Mexican energy regulator CRE and other government agencies have done everything possible under the president’s energy policy to limit Pemex’s competitors.

OPIS has detailed steps taken by the Lopez Obrador administration to favor Pemex, including suspending or restricting private fuel import and transload rail terminal permits as well as authorizations to import fuel outside customs points. 

But CRE still has some cards to play in its efforts to disadvantage Pemex competitors, including finalizing a 2022 package of proposed rules that would restrict sales between marketers and suspending distributors who have not complied with the government’s strategic fuel inventory requirements, sources told OPIS.

The agency, however, may not end up finalizing the rules because the provisions also could hurt Pemex and its network of branded suppliers.

Another market analyst said he believes Pemex’s market share has expanded in parallel with the revitalization of its network of retail fueling stations. 

The source said expansion into the retail sector by Pemex’s major private competitors has been hindered by CRE-imposed limits on new permits.

The number of Pemex-flagged retail stations rose by 222, or more than 3%, in the second quarter of 2023 to 7,080 from the same period in 2022. Pemex Chief Executive Octavio Romero Oropeza has said that the company has successfully stopped its losses in the retail sector because of the strategies it implemented over the last year.

A market analyst said private importers may over the short to mid-term limit imports due to Pemex’s growing presence in the market and their inability to expand their retail networks in the face of regulatory constraints.

An appetite for Mexico

Still, sources said that despite the nationalistic measures taken by Lopez Obrador and the regulatory barriers to private companies’ participation, Mexico continues to be an attractive destination for investment due to its proximity to the U.S.

“Mexico has always been an important market for refined product exports and will continue to be so,” one market participant said.

“There’s a narrative of self-sufficiency, but that’s something that is unlikely to happen.”

Even if all six of Pemex’s domestic refineries operate at 80% capacity and the new 340,000 b/d Dos Bocas becomes fully operational, Mexico’s demand for fuel would still exceed Pemex’s ability to supply it. The sources said it’s clear that the reality of the fuel market is at odds with what the government wants to achieve.

A number of sources are skeptical that Dos Bocas will contribute in any significant way this year to Mexico’s finished fuel supply, despite government promises. Most of the reports about upcoming production from the facility have been political in nature, with Pemex under pressure to reduce its reliance on imported gasoline from the U.S. 

Private fuel suppliers, however, could find themselves back in favor by 2025, depending on who wins the presidential election next year, an analyst said.

“The challenge is navigating the six-year term while anticipating a shift and ensuring survival along the way; the name of the game is to survive,” the source said.

–Editing by Daniel Rodriguez, and Jeff Barber, 

Starting Oct. 1, 2023, importers of downstream products including iron, steel, aluminum, electricity, fertilizers, cement and hydrogen into the European Union will need to report the carbon intensity level of these products to the Carbon Border Adjustment Mechanism (CBAM) Authority on a quarterly basis. 

Importers won’t have to pay any carbon levies just yet but are expected to do so by 2026 when the CBAM enters into full effect. While the CBAM will cover these sectors first, it’s highly likely that this tariff will increasingly include more downstream products and indirect emissions and, by 2030, cover all the sectors under the EU Emissions Trading System (EU ETS). 

So, what is the CBAM? 

To understand CBAM, we need to understand the EU Emissions Trading System (EU ETS), the carbon market that will determine the price of CBAM certificates, in other words how much importers will need to pay to cover the cost of emissions embedded within their imports.

CBAM Phased In as Free EUAs Go OutSince 2005, the EU has required industry within its borders to pay a market-based carbon cost under the EU ETS. In theory, the EU ETS aims to incentivize manufacturers to invest in decarbonizing by applying the principle of “polluter pays.” This means the more carbon dioxide an operator emits during manufacturing, the more money it should pay. With a limited number of EU carbon allowances (EUAs), which are expected to disappear by 2039, the price of pollution is expected to increase over the coming years. Exporters and importers in the EU will now have to keep the price of EUAs in mind: EUAs reached an all-time high in February, trading as high as €100.70 ($106.54)/mt and, more recently, traded at €85.27/mt on Sept. 25, 2023. 

Within the EU, the bloc provides hard-to-decarbonize sectors such as steel and cement manufacturers with free EU carbon allowances. However, with the introduction of the CBAM, this free allocation will be phased out gradually. EUAs will come to an end entirely by 2034 as the CBAM is simultaneously rolled out.

Essentially, free EUA allocation will be out and CBAM certificates will be in. 

The CBAM is part of the EU’s Fit-for-55 reform to reduce greenhouse gas emissions by 55% based on 1990 levels by 2030. The CBAM was provisionally agreed to by EU bodies in December 2022 and finally adopted by the EU Council in April 2023. 

With the EU having the most expensive carbon allowance in the world, entities sending their products to the EU will face the high carbon costs that EU industry is currently required to pay. According to the EU, the CBAM “would mirror the EU ETS effects for non-EU producers” and “encourage other countries to establish carbon pricing policies.” 

What is reported under CBAM?

EU importers will have to monitor and report the carbon emissions embedded in the products in question to the newly-created CBAM Transitional Registry on a quarterly basis starting Oct. 1, and the first report is due by Jan. 31, 2024. Importers won’t have to pay the carbon levy until Jan. 1, 2026.

benchmark EUA priceThose reporting data will need to provide: the total quantity of each type of product based in metric tons; the installation where the product was made; the total number of embedded emissions in tons of carbon dioxide for each ton of the product; country of origin and carbon price paid abroad. 

When the CBAM enters into full effect starting Jan. 1, 2026, the EU will require importers to file annual declarations by May 31 each year. The declarations will detail the amount of carbon emissions embedded in imported products during the last calendar year and how many CBAM certificates will be required to cover those emissions. 

For countries that already include a carbon cost — for example, China also has its own ETS albeit at a substantially lower cost than that of the EU — European importers will have to prove that a carbon price has been paid in a third country. As a result, the importer can deduct that cost from the CBAM certificate. 

Parties that do not report their CBAM declarations will face penalties of between €10 to €50 per metric ton of unreported emissions. 

Importers are those who will need to purchase the CBAM certificates, which will be calculated on the average weekly auction price of the EU ETS. If there are no auctions in a given week, the average of the previous week stands. CBAM certificates cannot be traded and will have limited validity. 

What will the next few years look like for CBAM? 

The transitional phase, from Oct. 1, 2023, to Dec. 31, 2025, will correspond to sectors with the highest risk of carbon leakage and with the highest carbon intensity in their products: iron and steel, cement, fertilizers, aluminum, hydrogen and electricity. 

The EU has said that the CBAM would eventually cover more sectors and that indirect emissions would also be included. 

The full CBAM will come into force on Jan. 1, 2026. 

“With this enlarged scope, CBAM will eventually — when fully phased in — capture more than 50% of the emissions in ETS-covered sectors,” the EU said. “The objective of this transition period is to serve as a pilot and learning period for all stakeholders (importers, producers and authorities) and to collect useful information on embedded emissions to refine the methodology for the definitive period.”

By 2030, the EU will likely extend the CBAM to cover all of the sectors already included within the EU ETS such as oil refining, upstream, all metals, pulp and paper, glass and ceramics, imports related to the aviation and maritime shipping sectors, and lime and chemicals. 

What does this mean for energy trade? 

As CBAM takes shape over the few next months, more and more countries with existing carbon schemes are considering implementing their own CBAMs. Earlier this year, the Australian and British governments voiced their support of a carbon tariff; countries like the US, Canada and Japan are considering doing the same.

Other countries like India and China, both of whom are among the world’s largest steel producers, have shown their opposition to the EU’s carbon levy, calling it a protectionist measure and bringing up complaints to the World Trade Organization. According to consultancy firm Wood Mackenzie, the carbon costs on steel alone could amount to a 56% increase for India and a 49% increase for China by 2034. 

As exporters to the EU face climbing carbon costs, many will likely divert their carbon-intensive products to countries without carbon levies while sending less carbon-intensive products to the EU. 

According to Wood Mackenzie, prices on commodities and products are likely to rise in the EU and low-carbon producers will have the chance to seize higher margins within the EU market. The consultancy firm’s research shows that the CBAM could provide more than $9 billion in revenues from the covered sectors by 2030.

Carbon capture and sequestration technology has been heralded by some as a savior for the US ethanol industry, but CapCO2 Solutions CEO Jeff Bonar insists that he has a better one.

Bonar’s company has collaborated with Adkins Energy to take steps to build the first facility to convert ethanol plant waste CO2 to green methanol.

“The Adkins board has approved the project. We’re just about done with the engineering study,” said Bonar.

The plan is to produce green methanol on-site at Adkins’ ethanol plant in Lena, Illinois. The output is expected to eventually reach 84,000 metric tons per year.

There seems to be little doubt in Bonar’s mind that the project will reach fruition.

“I’m very confident. Eighteen months ago, it wasn’t clear that there was an economic case for green methanol. Now, there’s a huge economic case for it. The production and demand for green methanol fuel is through the roof.”

Methanol is used in thousands of everyday products, according to Bonar, including insulation, gutters, roofing, paints, carpets, tires, plastics, fertilizers, cosmetics and even Lego bricks.

Methanol can also replace diesel fuel, he said, adding: “The traditional method of manufacturing methanol is fossil-fuel intensive, but ethanol can be made ‘green’ by using captured biogenic C02 emissions and renewable energy.”

bonar-jeffWhen green methanol is burned, it adds no new CO2 to the atmosphere, according to Bonar, making it a net-zero fuel.

“Methanol burns with no waste products, and even if spilled causes no environmental damage,” he said.

In addition to replacing carbon-intensive traditional methanol in consumer products, Bonar says it “can easily be used as a transportation fuel because conventional diesel engines can be inexpensively modified to run on green methanol.”

As evidence of green methanol’s popularity, Bonar offers the shipping industry, which he claimed “is pretty much standardized on green methanol,” citing its usage by Maersk and Amazon.

“There are now more than 200 ships commissioned to use green methanol. Even Disney Cruises has commissioned a green methanol ship. So there’s just no worry about green methanol being an important fuel.”

Technology Licensed From EU-based Company

CapCO2 says its technology, licensed from EU-based Real Carbon Tech, is efficient and easily deployed. CapCO2 has exclusive rights to sell it in the US.

The technology was developed by a researcher at a university in the Netherlands. It was commercialized by Real Carbon Tech, an engineering firm in Poland, and is already deployed at a cement plant there.

“The technology is basically proven. So what could go wrong? Now we just have to get it working in an ethanol plant, and I think the floodgates open.”

The company is concentrating on ethanol facilities because the output is greater, according to Bonar.

In addition, ethanol plant locations are “far simpler than the existing cement plant location,” he said, “so we don’t have any big engineering problems.”

The process is environmentally friendly, Bonar has said, because it captures carbon before it is released into the atmosphere, adding: “Also exciting are byproducts that can be sold as commodities rather than transported by pipeline and buried as waste.”

Furthermore, Bonar notes that the lower carbon index of green methanol makes it eligible for premium prices in low-carbon fuel markets.

There are other people pursuing green methodology, Bonar noted, “but they don’t have the technology.”

“Real Carbon Tech has three families of patents in 60 countries,” he said, “so I’m not worried about an immediate competitor for exactly their technology.”

A small pilot unit being built now is expected to be done by the middle of next year. That would be followed by 12 to 24 months to build a full-scale facility. Both are to be deployed at the Adkins plant.

“One of the advantages of our technology is that it’s modular,” Bonar said. “The pilot is one shipping crate. The full scale is eight shipping crates, all on the same patch of ground next to the plant.”

Financing Not Expected to be a Problem

“There are lots of people who want to loan money for a capital project that they know is going to produce revenue over 15, 20 or 25 years,” Bonar said. “We just have to have one plant proven working to do that.”

The US Dept. of Energy has a program in which “essentially they guarantee the loan for large infrastructure,” according to Bonar, who added: “They’ve said, ‘Your stuff sounds great. Get one running, and we’re very interested in guaranteeing financing for the full-scale project.'”

Bonar indicated that he can envision a scenario in which his company teams up with the carbon capture and sequestration projects planned in the Midwest.

“I could see the proposed pipelines ending up licensing our technology, concentrating some biogenic CO2 into a region and then having a methanol plant there,” he said.

Biogenic CO2 is the key ingredient for a diverse and valuable family of net-zero chemicals and fuels, according to CapCO2.

“If I were them, I’d be working on that hard because the burying of CO2, I don’t think, is a good business,” Bonar added. “Yeah, the government will pay you to do it for a few years, but is that really the model?”

CapCO2’s plan is to have 20 to 40 installations completed five years from now.

“We may set up a factory in either Illinois or Iowa or somewhere like that and build these shipping crates and crank them out,” Bonar said. “That would be a way to scale it up much more quickly than one at a time.

“We’ve got our hands full to do that for the next two years. We are busy. Right after that, who knows?”

In the meantime, Bonar will presumably keep extolling the virtues of his endeavor.

“Investing in pipelines rather than green methanol,” he says, “is the equivalent of investing in slide rule technology when the future is computing.”

–Editing by Jordan Godwin,