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The benchmark European Union carbon emissions allowance has traded at a premium to its British counterpart for over a year, and upcoming trade policies like the EU’s carbon border adjustment mechanism (CBAM) could impact British industry.

Read more: CBAM 101: The EU’s Carbon Border Adjustment Mechanism Explained

That’s unless the United Kingdom’s emissions trading system (UK ETS) and the EU emissions trading system (EU ETS) are linked to create a single carbon price for both entities, say some analysts who think that it could gain more traction if the Labour Party forms the next British government.

Brexit led to the departure of the UK from the EU’s carbon market and the creation of the UK ETS in 2021. The two carbon schemes cover heavy industry, but the EU market is substantially larger and more liquid than the UK ETS, covering over 10,000 installations, while the UK ETS covers several hundred.

Navigating the UK-EU Relationship

Linkage between the two carbon schemes is a real possibility according to Mark Lewis, one of Europe’s best known carbon analysts and the head of climate research at commodities hedge fund Andurand Capital Management. Lewis thinks that in the case of a Labour victory in the upcoming general election, Sir Keir Starmer, leader of the opposition party, will navigate a more subtle, less confrontational relationship with the EU.

While Starmer is unlikely to pursue an agreement to re-enter a single market with the EU, Lewis suggested to OPIS in an interview last month that merging the two carbon markets would be a way to show goodwill towards the EU and, perhaps more importantly, level the playing field between British and European industries.

“I think it makes political sense, and…it makes economic sense…It’s too early for the market to really start pricing [linking] in, but as we get closer to the UK election, I think what you will see is the carbon markets [in both the U.K. and the EU] think harder about how this might work,” Lewis said. “This will be an interesting narrative in the second half of the year.”

Linkage between the two carbon markets would be straightforward, Lewis said, especially as the British government has laid down a carbon reduction policy that is more ambitious than the EU’s. The EU has legislated for a 55% reduction in greenhouse gas emissions over 1990-2030 and has proposed a 90% fall by 2040 based on 1990 levels, while the British government has written a 68% reduction into law by the same year and then a 78% cut by 2035.

Linking would also provide British industry with access to a larger pool of carbon allowances, easing concerns about higher prices in the UK ETS in the coming years, Lewis noted.

The gap between the December benchmark contracts of the EU carbon allowances (EUAs) and UK allowances (UKAs) peaked in the fall of 2023 with a spread of over €40 ($43.33). That difference has narrowed to around €18 as EUAs traded on Tuesday at €58.72/mt and UKAs at £34.93/mt ($43.90).

The British government is also considering ways to provide more market certainty with respect to the UK ETS, which has seen prices dip from all-time highs around £97.75/mt on August 19, 2022 to an all-time closing low of £31.48/mt on January 29 this year. The government announced in December that it was working on the development of a supply adjustment mechanism akin to the Market Stability Reserve (MSR), which has been active in the EU ETS since 2018. The MSR mechanism aims to maintain competitive prices by either hoovering up allowances from the market or releasing them into the supply pool.

“The real point here is much more that the prices [between the EU and UK carbon schemes] are out of sync because the U.K. like the EU is frontloading allowances, but [the U.K.] doesn’t have an MSR,” Lewis said. “It’s raining hard outside with U.K. allowances, but at some point the drought in the U.K. is going to be more severe than in the EU because of the more ambitious [U.K. carbon emissions reduction] target.”

Riham Wahba, a senior market analyst with Vertis Environmental Finance, told OPIS that unless the U.K. introduces a supply adjustment mechanism into its carbon scheme, the government’s ambitions, like zero emissions in the power sector by 2050, could “break” the UK ETS as it calls for the faster decarbonization of British utilities, lower hedges and a ballooning total number of carbon allowances in circulation. Based on the government’s projections, power sector emissions would need to drop by 75% by 2030, 83% by 2035 and 98% by 2050 based on 2021 levels.

An EU official told OPIS that linking different carbon schemes is beneficial for climate action as it would allow for more cost-effective emissions reductions. The same official said that any decision to proceed with linkage with the UK ETS “remains to be explored” and that this would be assessed in light of potential changes to the EU ETS.

The EU Commission would need to get a negotiation mandate from the EU Council and the EU Parliament would also need to be involved in the ratification process, the official explained.

“Should the parties decide to link their emissions trading systems, in practice they would negotiate an international agreement. This was done recently with Switzerland, for example,” the EU official said.

On the British side, the Department of Energy Security and Net Zero (DESNZ) maintains an open position to linking with the EU ETS under the terms of the post-Brexit Trade and Cooperation Agreement, a DESNZ spokesperson told OPIS.

“We are open to the possibility of linking the UK ETS internationally and will continue to work collaboratively with other jurisdictions to tackle shared challenges and learn from the experience of others as we develop the scheme,” the DESNZ representative said.

Ben Lee, an analyst with Energy Aspects, told OPIS that while linkage between the two carbon schemes would face better chances under a Labour government, it would still be far from certain due to political, legal and administrative barriers.

Lower Exposure to EU CBAM through Linked Schemes

Wahba said that linking the two markets would help consumers avoid the price differential between the two carbon schemes and any resulting cost being passed through to consumers in the U.K. The CBAM, according to the EU Commission, was implemented to prevent ‘carbon leakage’, or domestic industry decamping to countries without carbon pricing or taxes. The EU Commission believes that the CBAM will encourage other countries to decarbonize their domestic industries

The mismatch between UK ETS and EU ETS carbon prices would mean that British industry is exposed to higher European carbon prices, potentially affecting the flow of trade from the U.K. to continental Europe. The British government announced in December that it would consider implementing its own CBAM but that this would only go live in 2027, a year after the EU’s carbon tax has gone into effect, with potentially harmful effects for British industry, according to accounting firm KPMG.

The EU CBAM will initially cover imports of cement, iron, steel, aluminum, fertilizers, electricity and hydrogen. The U.K. carbon border adjustment mechanism will include the same sectors with the exception of electricity and will also cover imports of ceramics and glass products.

Certain sectors of British industry have called for linkage with the EU ETS. UK Steel, a trade association, called for linkage in December to keep British exports to the EU afloat as 75% of the country’s steel industry’s exports — around 2.5 metric tons — are delivered to EU ETS-covered markets.

Demand for voluntary blue carbon credits from companies seeking to fulfill net zero pledges has surged in recent years, but geopolitical risks, limited verification capacity and high startup costs will likely prevent blue carbon credit supply from scaling up for years to come.

Companies want blue carbon credits — which are generated by coastal carbon sequestration projects — for their high quality and ability to diversify carbon storage portfolios.

But blue carbon projects account for just a handful of the 2,158 projects registered by Verra, a leading carbon credits registrar and verifier.

From April 21, 2022: ‘Huge Momentum’ is Underway for Blue Carbon

High demand for the credits and relatively expensive project costs have pushed the offsets to a substantial premium over forest-based credit alternatives in the voluntary carbon market.

OPIS calculated the Blue Carbon V23 Credits Average at $33.01/mt on March 13. On the same day, the REDD+ V23 Credits Average was calculated at $11.71/mt.

Blue Carbon vs. REDD+ V23 Average Price“It’s what everyone wants, but no one can get,” Arthur Wace, sustainability consultant with London-based carbon risk management and procurement firm Redshaw Advisors, said. “We have clients that have made net zero commitments for 2030 or even 2025. They want to invest in projects now. But the risks are too high.”

Sources said there are a few reasons for that, including that the blue carbon verification and credit issuance system is still in its early stages.

Project methodologies continue to develop, and it remains difficult and costly in many parts of the world to accurately measure the carbon stored in blue environments.

Further, it requires significant startup capital to begin to restore a coastal environment and it takes years to realize profits from credit sales. And many countries with blue carbon projects have yet to decide how to govern them. “The market is not in a position to scale,” Wace said. “But we’re getting there.”

Carbon Accumulation Rates Vary

As methodologies develop and researchers learn more about blue carbon environments, their climate diversity and carbon storage capacities are becoming clearer. Coastal mangrove forests, salt marshes and seagrass beds typically store carbon at a higher rate than forests and for longer periods.

Scientists estimate wetland environments store carbon at 10 to 20 times the rate of land forests, but others caution that comparisons are tough to make because of wide variations in both ecosystems. And while coastal wetland environments around the world are under threat globally, there’s no risk of them burning during periods of drought.

From April 20, 2022: Blue Carbon Pioneer Says Mangrove Tree Is the ‘Best Climate Machine’

A research team led by University of North Carolina Professor Antonio Rodriguez studied carbon deposits in salt marshes along North Carolina’s coast. In a study published in July in Nature, the group detailed the variations that occur depending on the age and growth of the ecosystem.

“If you look at carbon burial at different time scales, you get vastly different values,” Rodriguez said.

When salt marshes degrade, they begin to release the carbon they have stored.

But when restoration begins, as Rodriguez and his team found, carbon accumulation rates are high. Rates plateau as the ecosystem matures, but most of the carbon sucked from the atmosphere remains.

“That’s really important for offsetting because if you restore a salt marsh, then you’re going to benefit from that increased burial right away,” he said.

What’s more, as sea levels continue to rise, researchers expect the area viable for salt marshes will expand.

‘Can we even do this?’

Liz Guinessey is Verra’s food and blue carbon innovation manager and wetlands expert. Before that, she investigated GHG emissions and carbon storage in Georgia’s coastal wetlands for her master’s thesis.

“Back then, it was this question of, ‘Can we even do this? Can we get the quantification down pat enough to be able to potentially bring this carbon that gets stored to market?'” Guinessey said.

Despite the challenges, she said Verra has managed to develop ways to do so with confidence. “I think we’ve been able to figure out ways to deal with that uncertainty, deal with those fluctuations, and still be able to very clearly estimate at a conservative level what’s actually stored,” Guinessey said.

Still, blue carbon credit verification remains a developing practice. Verra released its first blue carbon methodology in 2020 and has since added three more. The organization is now in the process of consolidating the three into a single document.

Competing registry Gold Standard has not finalized blue carbon methodologies, although it said it’s developing a mangroves methodology with FORLIANCE.

Sources also said it can be challenging to find researchers with the expertise needed to verify a blue carbon project’s impact. And it’s a dirty job.

“Most are muddy, mucky environments,” Guinessey said. “You get literally absorbed by mud a lot of the time. These are not great conditions for field work. But I think that we’re getting to a point where it’s not becoming as challenging, especially with new technologies like remote sensing.”

Geopolitical Risk

As blue carbon methodologies develop and experts learn to understand and measure the environmental conditions, governments have grown wary of voluntary projects.

In one case, the blue carbon project known as Tahiry Honko was launched in 2014 by UK-based Blue Ventures and 10 small communities in Madagascar.

But in 2018, the Malagasy government argued the communities had signed a bad deal and placed a moratorium on the sale of carbon credits. None from the project have been sold, according to Mongabay, an online conservation news outlet. A number of voluntary offset projects that predate the moratorium remain in limbo.

Actions by other governments could also affect the projects.

India’s Power Minister Raj Kumar Singh in August announced a ban on the exports of carbon credits, though the government has offered no further information.

Some sources believe Singh was referring to carbon credits that would apply to India’s new compliance market, rather than those that would be sold on the voluntary market.

In recent months, Papua New Guinea, Honduras and Indonesia also have announced moratoriums on the sale of some credits. And many other countries have stepped in to regulate the voluntary market in some way.

“So many of these coastal systems are considered public goods under different jurisdictions,” Guinessey said. “So, getting either the government to sign on to a carbon project or figuring out some sort of concession to allow for a group to move in and actually develop a project can be a barrier.”

Where Are Blue Carbon Credits Headed?

Along with geopolitical risks and limited global blue carbon credit capacity, project finance is also a problem. Restoring blue environments is costly and it can often take several years before developers are able to start selling credits.

A number of companies are working to reduce the risks of carbon offset projects in general. Verra is developing credits that can be sold to generate startup capital to projects just getting off the ground. Insurance providers have also begun to underwrite projects against the potential invalidation of credits issued.

Still, the barriers to entry, particularly for communities in developing countries, remain high, sources said.

Analysts, however, expect buying interest in blue carbon credits will continue to rise.

“There is a general undersupply, and these projects are perceived to be of very high quality,” Anop Pandey, manager of market analysis for ClearBlue Markets, said. “We believe that any new supply will certainly get bought up quickly.

Also, as offset usage by corporations continues to receive more scrutiny, there will be more pressure for corporations to show the offsets they are using are of a high quality with large emission reduction and removal benefits.”

Stronger demand for the credits and price premiums are helping development efforts.

“In 2019-2020, you could buy a carbon credit from a REDD+ project for $6, $7,” Wace said. “Now, as prices have come up, we can begin to bring on higher impact projects.”

At the same time, the buyers for blue carbon offsets are mostly large tech companies with significant cash flows.

“Will other corporate industries be willing to pay for these projects?” Pandey asked. “In other sectors with companies that have smaller budgets for offset purchases, but still have high emissions, maybe not. As such, the demand and supply of these projects will need to find a balance.”

Blue carbon projects face other risks, including the environments’ ability to survive and continue to sequester carbon for decades.

During six-month period in 2016 and 2017, for example, between 40 and 50 million mangrove trees in Australia’s Gulf of Carpentaria died. The culprit was an exceptionally harsh El Nino climate that dropped coastal water levels by 40 centimeters for roughly six months.

Still, with cooperation between government and private industry, experts expect blue carbon credits will eventually provide a crucial, high-quality means of carbon sequestration at scale. But it remains impossible to say exactly when that will come to pass.

With the integrity of carbon offsetting under fire, buyers are looking to lock down the forward delivery of high-quality credits from trusted climate projects, but there’s just one problem: some offset project developers don’t want to play ball.

From accusations that climate projects have disadvantaged local communities to claims of fraudulent carbon credit issuances, market proponents have weathered a hail of criticism in recent months. In response, some corporate buyers have ramped up purchasing due diligence and pushed for contracts that guarantee a fixed volume delivery over time.

This last point has given some sellers pause, such as Kennemer Eco Solutions Co-Founder and Technical Climate Lead Florian Reimer.

“For us, as a new market entry developer with only two projects, we would never sign such a liability,” Reimer said. “I think many smaller developers would feel uncomfortable with that.”

Hunting High-Quality Credits

During the last eighteen months, the voluntary carbon market has been characterized by trade illiquidity and a slump in prices after growth surged through the first half of 2022.

OPIS REDD+ V23 Credits Average Price chartThe OPIS Voluntary REDD+ Credits Average current-year price declined to below $12.50/mt in March 2024 from a peak of above $16/mt in October 2022.

According to analysts, corporate purchasers are growing more careful.

Project developers have mostly kept up with bolstered demand for high-quality credits, but that may be changing. Credit retirements across the five largest registries outstripped issuances in 2024 until the last week of February. As of March 10, 48.2 million credits had been issued and 42.2 million had been retired.

Current market dynamics also reflect scientific debate over emissions reduction baselines and the volume of carbon that projects sequester, as exemplified by reporting in January from U.K. news outlet The Guardian.

Conditions have been exacerbated by the fact that the voluntary carbon markets are still structurally and operationally underdeveloped, sources said.

The Rocky Road to Project Revenue

It can take several years of work and significant investments before a climate project yields any income.

Climate projects are often built in a shifting, dynamic landscape, prone to upheaval from natural and human forces, and verifiers can only estimate potential emissions reductions. Actual credit issuances might significantly exceed or miss those expectations.

If a project is sufficiently capitalized, this last point is irrelevant because the developer can afford to wait for credits to be issued before it sells them.

But if a developer needs to fund operations before credits are issued, it may sign contracts that promise credit delivery on a forward basis.

The Role of Forward Delivery

Industry stakeholders generally agree that forward delivery contracts can play a crucial role in developing the market. But once the details of forward emissions reduction purchase agreements come into focus, buyers and sellers sometimes find themselves at odds.

One key sticking point involves the volumes of credits delivered. Some ERPAs (known as proportional forward ERPAs) require the project developer to deliver a percentage of the credits they ultimately issue. Others prescribe a fixed volume for future delivery (and are known as fixed forward ERPAs).

For a fixed forward contract, a developer must make up the difference if their project doesn’t produce enough credits to fulfill the order.

“New carbon projects launched by smaller developers are high-risk ventures,” Reimer said. “The buyer or investor is usually the financially stronger party.

“This is an early-stage capital investment associated with high returns but also high risks,” Reimer added. “I think smaller developers argue that those parties need to carry the risk of delayed issuances, and traditionally that has been the majority of cases. We find no problem in financing our projects via forward contracts without a replacement credit liability.”

Fixed forward contracts, however, are becoming more commonplace, and developers’ ability to avoid such circumstances may be shifting.

In February 2023, the International Emissions Trading Association released framework ERPAs intended to serve as a blueprint. The IETA forward ERPA included language that secures fixed forward delivery.

If a carbon offset credit shortfall “beyond the reasonable control of the Seller” occurs “the Seller shall instead be obligated to Transfer Comparable VCCs in an equal number to the shortfall and otherwise in accordance with this Agreement as soon as reasonably possible,” according to the document.

This Primary ERPA (along with a related Contingent Secondary ERPA) “is intended to provide a minimum benchmark for transacting emissions reduction and removal credits by including basic provisions relating to the transaction of such credits,” according to an IETA news release.

Are Strong Risk Protections Counterproductive?

The company Respira manages a portfolio of high-quality voluntary carbon offset credits. According to CEO Ana Haurie and Director of Business Development Will Close-Brooks, it prefers to sign proportional, not fixed, forward ERPAs.

“When you’re trying to contract on a forward basis, you need to build risk mitigation into your arrangements,” Haurie said. “We just need more certainty. I hope that high-quality project developers won’t be put off one way or the other.”

Close-Brooks said, “We want the project [with which we transact] to continue to be viable and to be successful. So, I would say we’re very interested in mutually sharing risk and trying to be pragmatic.”

Mike Korchinsky, whose conservation organization Wildlife Works is primarily funded through REDD+ credit sales, sees another wrinkle in this dialogue.

“We believe in market mechanisms,” Korchinsky said. “We have seen the evolution of the market from its origin. [Fixed forward ERPAs] are going to work well for high-volume buyers in the global North. Oftentimes, that’s at odds with the people who actually bear the cost, the true cost of change.”

In Korchinsky’s view, the local and indigenous communities that often must change their way of life to support a project are too-often ignored in transactions. If too many deals occur that don’t adequately serve their needs, they could grow reluctant to collaborate.

“Imagine a community that has begun work on a carbon project,” Korchinsky said. “It hasn’t received any funding for the work it has done. Then the project doesn’t deliver for whatever reason. They can be held accountable to the buyer for the market value of replacement credits. It’s not malicious; it’s short-sighted. If the buy side tries to be too self-serving, it can be counterproductive.”

Voluntary carbon credits forward delivery contracts are unique for another reason. Unlike other sectors, the contracts can’t be easily used to secure funding from a third party. That reality has frustrated ALLCOT CEO and Founder Alexis Leroy, whose business develops both renewable power and carbon offset projects.

“If I were building renewable power, I could get a power purchase agreement, walk into the bank the next day, and they would finance 75%, 80% or maybe even more than 100% of the project,” Leroy said. “But with an ERPA, no bank in the world would provide us with capital.”

Risk Tools, Insurance Enter the Picture

Still, the IETA ERPAs only represent a starting point in negotiations. Contracts signed by sellers and buyers tend to be highly specific depending on project specifications. Forward carbon offset insurer Kita CEO Natalia Dorfman has witnessed this firsthand.

“Any time you negotiate a contract where the two parties don’t necessarily have a view of what everyone else in the market is doing, you create the potential for imbalances on either side,” Dorfman said. “I’ve seen ERPAs that are wholly unfair to the project developer. I’ve seen somewhere the buyers are taking on significant amounts of risk. And I’ve seen others that are less than a page in total. One of the key challenges within the market is that it lacks the basic underpinnings it needs to scale.”

Contract reform, furthermore, isn’t the only tool stakeholders have at their disposal. Insurance providers, including Kita, Parhelion, Howden Group Holdings, Oka and others, have begun to underwrite aspects of VCM projects and transactions.

“Even with the best ERPA, all it can do is pass risk up or down the chain, ultimately to the buyer or the seller of the offset,” said Parhelion CEO Julian Richardson. “The problem with this is that contract counterparties might not be willing or able to accept the risk. There is no point forcing your counterparty to accept the risk if their balance sheet is limited or they are not creditworthy. By bringing highly rated insurance paper to the table, we are giving counterparties a creditworthy third party to transfer the risk to.”

A number of carbon credit ratings agencies, such as Calyx Global, Sylvera and BeZero have also launched to provide third party credit quality information.

“In terms of securing future ‘quality’ supply, this is a super interesting topic,” said BeZero CEO and Co-Founder Tommy Ricketts. “The surge in pre-issuance market activity, notably for engineered and nature-based removals, has come with rising calls from our clients for pre-issuance risk tools. Not surprisingly that’s something we are investing in heavily. I think that will be a big trend for 2023.”

Buyers and sellers of voluntary carbon credits have, in recent months, begun to value offsets issued from the same projects at wildly different prices.

Vintage 2021 credits from an Asia-based REDD+ project traded in February 2024 at $16/metric ton. In January, a seller offered V18 credits from the project at $1.25/mt. V21 credits from a Latin American REDD+ project traded in February at $10.10/mt and $6.50/mt. Since October 2023, credits of various vintages from an Africa-based REDD+ project have cleared between $1.70/mt and $5/mt.

REDD+ stands for reducing emissions from deforestation and forest degradation.Voluntary carbon markets are notoriously opaque. Credits can transact on electronic exchanges either through direct trades or in standardized contracts. Many deals, however, occur on a bilateral basis. Buyers may also sign forward offtake agreements with developers for future issuances.

In that milieu, buyers and sellers can arrive at varying conclusions regarding the quality of a carbon offset project and the value of its credits.

In Search of Quality

REDD+ projects have received harsh criticism over the past two years. John Oliver detailed a range of low-quality initiatives in an August 2022 segment on the HBO show “Last Week Tonight.” In a January 2023 article, The Guardian alleged that “more than 90% of rainforest carbon offsets … are worthless.”

In the months since, further criticism of voluntary carbon markets has proliferated. In response, the market has flocked to quality.

Many buyers have reported seeking out high-quality credits. The Integrity Council for Voluntary Carbon Markets is working to signal quality by assessing methodologies under its Core Carbon Principles framework, which it published in March 2023. The Voluntary Carbon Markets Initiative has begun to approve corporate offsetting statements with its Claims Code of Practice, which it published in June 2023.

General agreement exists among market stakeholders as to what constitutes a quality REDD+ project. Among other measures, projects should be additional, meaning they would not have occurred without the intervention of the developer. Offsets should be permanent, meaning developers should reasonably expect to sequester carbon on an ongoing basis and put measures in place to address the risk of reversal. Credits should be counted just once and then retired. Projects should not simply displace carbon emitting activity somewhere else, known as leakage.

And, per the ICVCM’s principles, projects should ensure “robust quantification of emission reductions and removals.” In other words, if a project issues a credit representing a metric ton of carbon dioxide equivalent, or CO2e, it should be confident that a metric ton of CO2e has been removed, reduced or avoided.

Finally, credits can also earn co-benefit designations for advancing sustainable development goals or other benefits that do not directly relate to carbon offsetting. Many buyers pay a premium for strong co-benefit designations.

Yet, as evidenced by the disparity in prices reported to OPIS for credits from the same project, buyers and sellers can disagree over how quality translates to price.

Carbon credit ratings agencies, such as BeZero Carbon, Sylvera and Renoster, have brought greater clarity to the market, but the availability of ratings doesn’t necessarily lead to price consistency.

For example, V20 credits from an Asia-based REDD+ with a co-benefit designation traded in September for $13.50/mt. V20 credits from the same project were offered at $5.75/mt in January.

OPIS assessed the REDD+ V20 Tier 3 range at $6.75/mt to $14.75/mt on the day of the trade in September. The range was assessed at $5.10/mt to $16/mt at the end of January and was assessed at $5.50/mt to $14/mt on March 5.

Renoster rates projects based on its confidence that one credit represents one metric ton of offset emissions. An ideal score is 1. Anything above that level indicates the project has understated its impacts, and anything below indicates it has overstated them.

Renoster gave the Asia-based REDD+ project a score below 0.80. While it was judged to be additional and to have set a conservative baseline, leakage involving deforestation in nearby areas brought its score down. Significant permanence risks were also detected.

Widening Spreads Between High- and Low-Quality Credits

As carbon offset buyers began to conduct greater due diligence regarding project quality over the past 18 months, prices reflected that shift. Buyers began to pay a premium for credits they deemed to be high-quality, while sellers of credits perceived to be low-quality grew willing to trade them for less and less.

OPIS accounts for project type, vintage and volume, as part of its voluntary carbon market assessment range. Over the past year, the spread between the high and low end of OPIS assessments has widened.

On Jan. 18, 2023, the day The Guardian published its article, OPIS assessed the REDD+ Tier 3 V21 range at $10.44/mt to $14.50/mt. On Tuesday, the REDD+ V21 Tier 3 range was assessed at $6.25/mt to $15.07/mt. In the interval between, the low end was assessed as low as $5/mt on Feb. 7, 2024, while the high end was assessed as high as $18.50/mt on March 30, 2023.

In other words, the market has weakened overall, but some projects perceived to be high-quality have been able to fetch stronger prices than they could 12 to 18 months ago.

BeZero Carbon Co-Founder and Chief Innovation Officer Sebastien Cross has also noticed this phenomenon.

“We’ve begun to see big spreads in the market, particularly after last year, when you saw some of the pricing crash off of some of the stories and headlines,” Cross said. “But, if you look at the underlying transactions going through, some projects have still been appreciating.”

Some disparity in prices can be explained by the volume of credits delivered in a trade. Sellers typically ask more for credits in smaller-volume transactions.

OPIS divides its assessments by tiers to account for these volume discounts and premiums. Tier 3 involves trades between 2,000 and 49,000 credits, Tier 2 reflects volumes of 50,000 to 349,000 credits, and Tier 3 is 350,000 credits and above.

Credit vintage can also influence pricing. Newer vintages tend to trade at a premium to older vintages, which represents a contango market structure.

But disparity can be found in credit prices from the same project even accounting for vintage and volume. Since December 2023, Tier 3 volumes of V19 credits from a Latin American REDD+ project have traded between $8/mt and $13.45/mt. Less than a year ago, Tier 3 trades for V19 credits from the project cleared as high as $17.50/mt.

What’s more, the project has a rating from Renoster well above 1, indicating very high confidence in its emissions reductions and project quality.

While the previous example of the Asia-based REDD+ project indicated that some buyers were overpaying for middling quality credits, Renoster’s rating of the Latin American REDD+ project indicated that some buyers have been able to pay less for high-quality offsets.

According to Saif Bhatti, CEO and Co-Founder of Renoster, this disconnect indicated how immature the voluntary carbon market remains.

“This is a very nascent market,” said Bhatti said. “There’s just not a high level of liquidity or information transfer from different market participants. If you compare it to the stock market, the price of the same share on one exchange is likely to be the same as the price on another. That’s obviously not the case here. It’s just such a different ballgame.”

Both Bhatti and Cross, however, believe buyers are getting smarter and savvier when it comes to judging quality.

Cross pointed out that The Guardian article based its broad conclusions on a sample of the REDD+ market. When it was published, it had a strong impact on REDD+ prices.

“The market has progressed a lot,” Cross said. “The marginal impact of these headlines [criticizing carbon projects] has been less and less. People have realized that taking a sub-sample of a sector and saying, ‘These projects are crap, therefore the whole sector is crap and therefore the whole market is crap.’ That is not actually an indication of reality. You have to be a bit more specific.”

See also: REDD+ Project Hedges Against Drought and Weakening Carbon Markets, June 1, 2023

Nature-based carbon removals projects can create valuable credits that command price premiums over avoidance and reduction credits. But they are also hard to scale, and it will take years to meaningfully increase stocks of forestry removals credits in the voluntary carbon market.

Several headwinds have slowed nature-based carbon removal credit issuances. They include difficulty in getting some auditors to regularly verify stored carbon, a short supply of appropriate land and difficulty in persuading property owners to transition from agriculture production or other uses.

In the face of criticisms regarding project integrity, developers want to proceed slowly to ensure their projects produce reliable, high-quality credits. Meanwhile, popular Blue Carbon and Afforestation, Reforestation and Revegetation projects face a more fundamental speed limit: it takes time and resources to grow a tree.

From Degraded Field to Forest

Nature-based carbon removal projects involve replanting degraded or cleared ecosystems. The trees and vegetation they grow actively remove carbon from the atmosphere.

By comparison, reduction projects reverse deforestation, install carbon-free power generation or replace cookstoves with more efficient devices that emit less greenhouse gases, among other activities. Land conservation projects avoid emissions that would have otherwise occurred.

Many ARR developers have highlighted how difficult it can be to grow a forest on cleared land.

U.S.-based developer GreenTrees partners with landholders in the Mississippi Alluvial Valley to convert their properties into ARR projects. In most cases, owners previously used their land to farm crops like soybeans and corn.

According to GreenTrees Co-Founder and Managing Partner Chandler Van Voorhis, that land-use transition can be a tough sell.

“With [Reducing Emissions from Deforestation and Forest Degradation] and [Improved Forest Management] projects, you’re changing the way you manage an existing asset,” Van Voorhis said. “With ARR, you’re making big capital investments. You have different yield curves. You’re going from a known cash position to uncertainty. That is a different kettle of fish.”

Van Voorhis described carbon removal and resulting profits from an ARR project as an S curve.

It can take several years before a new project begins to generate credits and, in those early years, issuances are typically meager.

Landowners should look at afforestation not as they would a crop, but as a generational change in how they use their land, Van Voorhis said.

One ARR project getting underway in the Democratic Republic of Congo exemplifies the slow pace at which afforestation occurs.

Project developers ALLCOT A.G., Graine de Vie and Fanyatu have allotted 9,400 hectares to regrow with a mix of forest and fruit trees that will provide a cash crop for participating communities to sell. In their project description filed with carbon credit issuer Verra, the developers expected to remove zero greenhouse gas emissions in the first year. The second year is projected to remove just under 4,000 metric tons. But by the 10-year mark, the project will possibly remove more than 600,000 mt of C02 per year.

Keeping Growth Slow to Maintain Quality

REDD+ projects have received criticism over the last year for alleged errors in emissions avoidance calculations.

ARR developers are worried about the potential for similar criticisms and want to take steps to ensure their projects reliably sequester carbon. But doing so can further slow the pace of growth, sources said.

U.S.-based Chestnut Carbon launched in 2022 and started to regrow land they own and manage. The company announced their first contract with Microsoft in December 2023 for the forward delivery of 362,000 ARR credits. But the first credits won’t be delivered until 2027.

The deal comprised roughly 70% of the credits the company expects to issue from their first project, Chief Commercial Officer Shannon Smith said. “Part of that is just giving us a delivery cushion to make sure that, if there’s any shortfall in credits the trees actually deliver, we won’t have any trouble meeting our obligations,” Smith said. “But we’re also leaving some credits to sell on the spot market because we’re expecting the credit prices to be higher five years from now.”

According to Chestnut Carbon Chief Financial Officer Greg Adams, it would theoretically be possible to plant forests that grow faster and issue credits sooner. But that could sacrifice the project’s quality.

“We do not want to overpromise and under deliver,” Adams said. “We want to make sure we do it right. Given the criticism that has been leveled against this space, it’s really important to us that our growth does not come at the expense of compromising the integrity of our product. Full stop.”

Due to the slow pace and significant upfront costs, ARR project proponents have developed creative and diversified business models that do not favor rapid expansion. Many are also combined with community development or biodiversity initiatives.

The Australian organization WithOneSeed launched an ARR project in Timor Leste in 2010.

The country experienced significant deforestation in the 20th century, in part, due to its invasion and occupation by Indonesia from 1975 to 1999.

WithOneSeed supplies farmers with tree seedlings and pays them 50cts per tree per year through ARR credit sales. As of 2023, farmers participating in the project were managing more than 450,000 trees.

Forest First Colombia was also established in 2010 in the Vichada region of the Latin American country where much of the landscape has become degraded grasslands. The company generates revenue by growing a portion of trees to be harvested for timber, while the rest are set aside to develop into a forest and produce removal credits. Registered under Verra’s Climate, Community and Biodiversity Standards, it provides employment to 200 people in the area and has established a wildlife habitat for several threatened species.

“If you have unlimited funds, you could replant an area and just leave it, right?” said Forest First Co-Founder and Chief Financial Officer Jonathan Dodd. “That’s a very benevolent way to do it. But doing that on any scale is really impractical. You have to marry financial return with the ability to provide this sequestration with the co-benefits.”

ARR, Blue Carbon Prices Up with Demand

Demand for removal credits has remained strong, in part, because many buyers believe they have a higher climate impact than other types of credit. These projects not only reduce emissions in the atmosphere but potentially create numerous other benefits for their surrounding regions, including increased biodiversity, erosion reduction and boosted soil nutrients.

As media and academic criticisms of REDD+ projects have intensified over the past year, many buyers have sought out removal credits as a higher-quality alternative.

Removal credit retirements for projects registered with Verra, Gold Standard, Climate Action Reserve and the American Carbon Registry hit a record high of 19 million in 2023, up from 18.3 million in 2022, according to ClearBlue Markets Manager of Market Analysis Anop Pandey.

But while demand for removal credits is on the rise, supply remains low. The total stock of credits in the global voluntary carbon market is dominated by reductions and avoidances, and that share is growing.

Removal issuances fell steeply last year. Total issuances for carbon offset projects under the same registries came in at 249.68 million credits in 2023, Pandey said. Of that, just 11.5 million were from nature-based removal projects.

By comparison, removal projects issued 25.1 million credits in 2021 and 24.3 million credits in 2022.

Strong demand and low supply caused ARR prices to maintain a steady premium over REDD+ through the year.

Looking at V19 – a vintage that maintains a significant source of supply in the market – the average OPIS ARR assessment began 2023 at $12.553/mt. It hit a yearly low of $10.683/mt in February, jumped to a yearly high of $17.303/mt in March and finished the year at $12.158/mt.

By comparison, the REDD+ V19 average assessment started 2023 at $11.053/mt, just $1.50 below ARR. It hit a high of $12.85/mt in March, sank as low as $7.483/mt in June and finished the year at $9.125/mt.

The average prices mask wide fluctuations related to perceived credit quality. The spreads between the low and high of the OPIS assessments for ARR and REDD+ widened significantly over the course of the year.

ARR V19 Tier 3, which reflects a volume of 2,000 to 49,000 credits, started the year in a range of $11.46/mt to $14.48/mt. By Dec. 29, the range had widened to $6.80/mt to $18.75/mt. REDD+ V19 Tier started the year in a range of $9.96/mt to $12.98/mt and that range had widened to $4.25/mt to $16/mt in December.

Some developers said they have signed forward deals far above the OPIS range. The Brazilian ARR developer Mombak publicly reported a deal with McLaren Racing in November for the sale of credits at over $50/mt. OPIS has been unable to verify key details of the transaction, such as the overall volume of credits delivered.

One source has reported selling ARR credits at an even higher rate, but that could not be confirmed by OPIS.

The Outlook for Removal Credit Supply

Due to the slow growth of credit issuances and a general lack of available land to develop more removal projects, analysts do not expect there will be a strong rise in removal issuances in 2024.

“The long time needed to be able to start monetizing credits, combined with the high costs needed to develop these projects, would limit the number of nature-based removal credits that could be produced, despite the expected increase in demand,” Pandey said. “It’s also becoming increasingly difficult to get lands for ARR. Convincing the investors that the project is not going to engage in conversion of native ecosystems is getting harder, as many VCM [stakeholders] increasingly frown upon this as ever-restrictive environmental and social safeguards are put in place.”

Maintaining the pace of issuances has also become a challenge for some developers. Van Voorhis of GreenTrees says his aggregated project ideally issues every year to both satisfy forward sales agreements and return revenue to participating landowners on a regular basis.

But the monitoring, reporting and verification process has slowed, in part, due to difficulties related to getting GreenTrees’ project verified by certified third parties. “First, you need to get on a verifier’s schedule,” Van Voorhis said. “Then you can start verification, which can take nine months. It’s an intensive audit. If you start in January, and you’re lucky, you get credits by September. That’s in an ideal world. The reality is there are so many projects and only so many verifiers. We can’t even get an initial meeting with verifiers until later this year. Sometimes the issuance schedule has nothing to do with us.”

Dodd of Forest First Colombia also initially sought an annual verification process to keep up with forward delivery agreements. But he says COVD-19 slowed project growth in unexpected ways. “The pandemic inhibited our ability to plant and inhibited our ability to raise money,” Dodd said. “In fact, it still does to a degree. So as of today, we’re behind where we thought we were going to be in 2018.”

Ultimately, the project developers OPIS contract by OPIS expect increased demand will be bullish for removal prices. But at least in the medium-term, there’s little hope that issuances will meaningfully increase supply.

Many of the fundamentals that drove North American compliance carbon market prices to record highs in 2023 — including formal program reviews and supply side adjustments — will remain at center stage in 2024.

California-Quebec Joint Cap-and-Trade Program’s Momentum

California and Quebec on Jan. 1 marked the 10th anniversary of the linkage of their joint cap-and-trade programs, but even after a decade, the programs continue to evolve. The California Air Resources Board (CARB) in 2023 worked on proposed amendments to its cap-and-trade regulations, and that process will continue in 2024.

Discussions of increasing emissions reductions targets while addressing potential allowance oversupply helped to push California Carbon Allowance prices higher in 2023, with values rising to a record high of $39/metric ton in December for current year prompt delivery, up from $27/mt at the start of 2023.

The California-Quebec joint cap-and-trade quarterly allowance auctions also had strong buying interest, with each selling out and reaching an all-time high settlement price of $38.73/mt in the fourth quarter of 2023.

The upward momentum is poised to continue in 2024. “We are expecting CARB to finish the program review process sometime in 2024, with different price points depending on what scenario CARB ends up choosing,” said Anop Pandey, an analyst at ClearBlue Markets.

Depending on which 2030 emissions reduction target CARB decides to enact, CCA prices could end 2024 at $45.50/mt if the 40% target is adopted, $52.06/mt if the 48% target is adopted, and $68.45/mt if CARB moves forward with the 55% target, Pandey said. “As of now, we still think 48% is the most likely scenario,” he added.

CARB also proposed allowance supply changes that have the potential to give prices additional lift and is considering allowance budgets that could remove between 115 million to 390 million CCAs from either future auction price containment reserves, price ceilings or auction and allocation pools. And the agency is evaluating holding limits on banked allowances.

In addition, Quebec is mulling changes to its California-linked cap-and-trade program, including strengthening the province’s emission-reduction goals, limiting the use of offset credits for compliance purposes and the possible removal of 17 million allowances from the supply pool between 2025 to 2030.

Washington State’s Evolving Cap-and-Invest Market

Meanwhile, Washington state’s cap-and-invest market begins 2024 on the heels of an active inaugural year of secondary market price swings and regulatory adjustments.

In 2024 the state Department of Ecology will continue to pursue linkage with the California and Quebec programs under the Western Climate Initiative (WCI). While such a linkage, if agreed to by all parties, would not occur until 2025, Washington has prepared a number of proposed program and legislative changes it will focus on in 2024 to align its program more closely with California and Quebec’s.

Yet a more immediate factor that could affect prices in the new year is the updated allowance price containment rules that the Washington Department of Ecology announced in late 2023 in response to rapidly rising compliance costs.

In 2023, both the second- and third-quarter Cap-and-Invest auctions triggered supplemental Allowance Price Containment Reserve auctions after settling above the $51.90/mt trigger price.

At the Cap-and-Invest program’s first-ever APCR auction in August 2023, the reserve allowances offered were split between the $51.90/mt Tier 1 and $66.68/mt Tier 2 prices. In that fully subscribed APCR auction, Ecology sold all 527,000 WCAs offered at the Tier 1 APCR price and 527,000 WCAs offered at the Tier 2 price.

After a second APCR auction was triggered in the Q3 allowance auction, Ecology announced that the second APCR auction in November would offer allowances only at the Tier 1 price of $51.90/mt rather than both the Tier 1 and higher Tier 2 prices.

Regulators also announced allocation of an additional 1 million reserve allowances for 2024, pulling from the 2026 APCR pool to increase supply earlier in the first compliance period.

Those changes seemed to have had the desired impact, as the regularly scheduled fourth quarter auction settled below the APCR trigger price.

Amid these program updates, OPIS WCA price assessments dropped about $15/mt from early September (before the Q3 auction results) to around $52/mt by mid-December 2023.

Pandey forecast current vintage WCA prices of $56.57/mt in the secondary market for 2024, with price signals continuing to come from Washington-specific fundamentals, despite the state’s intent to link to California and Quebec’s program in the future.

“As of right now without reciprocal announcement from California and Quebec, we do not expect the Washington linkage announcement to have an impact” on WCA prices, Pandey explained. In the meantime, Washington allowance prices “will continue to reflect the market fundamentals of Washington only.”

Regional Greenhouse Gas Initiative Prices at Record Highs

On the East Coast, Regional Greenhouse Gas Initiative (RGGI) allowance prices begin 2024 at or near record highs, propped up by similar fundamentals to those seen in California: the prospect of tightening allowance supply and emissions reductions goals amid a formal program review.

Secondary market allowance prices climbed above $15/st in December, as the Q4 auction clearing price rose to a record high of $14.88/st. The auction settlement price also triggered the release of cost containment reserve allowances for the first time since 2021.

The current program review began in 2021 and was expected to conclude by the end of 2023. The process will however extend into 2024.

The short-term upside for RGGI prices may be capped by a 2024 CCR trigger price of $15.92/st, at least pending further developments from the ongoing program review, which have the potential to shed light on future allowance supply fundamentals.

Meanwhile, the list of RGGI member states is also set to shrink in 2024. Virginia is on track to withdraw from RGGI by the end of 2023 following the state’s Air Pollution Control Board vote in June to end its participation in the program, fulfilling a campaign promise to do so from Gov. Glenn Youngkin.

In Pennsylvania, a Commonwealth court in November barred the state from participating in the program, ruling that revenue raised from the program was an “invalid tax” that the Department of Environmental Protection does not have the constitutional authority to collect.

Pennsylvania’s active participation in the program was immediately put on hold pending the outcome of legal proceedings.

Pennsylvania Gov. Josh Shapiro appealed the most recent decision to the state’s supreme court in November, although Shapiro’s level of commitment to RGGI itself is unclear.

“The Commonwealth Court’s decision on RGGI – put in place by the prior administration – was limited to questions of executive authority, and our administration must appeal in order to protect that important authority for this administration and all future governors,” a Shapiro spokesperson said in a statement following the appeal.

Shapiro has previously expressed both concerns about RGGI’s efficacy in achieving the state’s climate goals as well as an openness to considering potential alternatives.

Meanwhile, Regional Greenhouse Gas Initiative member state New York is expected to publish draft rulemaking on its forthcoming cap-and-invest program in 2024, with a potential program launch in 2025.

The design of the cap and invest program will take into account the state’s ongoing participation in RGGI and is being developed to allow future linkage with established emissions trading programs, such as California or Washington, according to state officials.

–Editing by Kylee West, kwest@opisnet.com and Jeff Barber, jbarber@opisnet.com 

The British government is considering introducing legislation to close a loophole in its Emissions Trading System, which has resulted in the UK handing out free carbon allowances to the operators of offline installations who have then reaped windfalls by selling the pollution permits for cash.

The move follows in the wake of a series of reports by OPIS over the last year, which have shown that the UK and several EU governments have handed free carbon allowances worth more than $400 million to offline plants operated by some of the world’s largest steel, oil, fertilizer and chemicals companies.

The loophole might even have had the unintended consequence of encouraging operators to shut down plants.

In effect, the loophole has resulted in the operators of offline plants being handed pollution coupons, but rather than polluting and handing back those coupons to governments, operators have sold them on for cash.

In the words of the Wall Street Journal’s Ed Ballard, who wrote in October about OPIS’s investigation: “In Europe, big polluters are getting paid for doing nothing…These [free] permits are supposed to be used to prevent companies with few options for reducing emissions from being saddled with crippling costs.”

In some cases, the loophole might even have had the unintended consequence of encouraging operators to shut down plants in the UK and EU, rather than do the hard yards of investing to decarbonize their installations.

For example, an installation operator, knowing that it will receive free allowances worth, say, $50 million, at the start of a calendar year, might be tempted to shut down its European plant, emit a tiny amount of carbon, sell on its surplus free allowances and use the proceeds to provide severance pay to workers and dismantle the site.

A consultation document released in December 2023 by the UK government’s Department for Energy Security and Net Zero on revising the allocation of free allowances to installations conceded that “current rules relating to permanent cessations can… lead to some operators receiving more free allowances in the final year of activity than they require.” The government said that it was “minded to amending the permanent cessation definition either through legislation or alternative routes, such as the publication of guidance.”

How the Loophole Enabled Some to Take Advantage of the System

Most polluters subject to the cap-and-trade EU and UK emissions trading systems must buy EU and UK emissions allowances through auctions or via open markets on the ICE exchange, with one such pollution permit allowing a company to emit one metric ton of carbon into the atmosphere.

Often installations identified by OPIS were not operational at any point during a calendar year but their operators were still handed free allowances that were used to cover the costs of emissions at other plants or were sold on to other emitters for cash.

But operators in several hard-to-decarbonize sectors such as oil refining, steel and chemicals receive allowances for free every year from domestic governments. If those operators cut their emissions, they are able to sell surplus free allowances to other emitters, thereby profiting from decarbonizing their assets. The free allowance systems are designed to prevent operators in these sectors from being undercut by imports from countries where there are no levies on emitting carbon.

However, dozens of UK and EU installations have continued to receive free allowances from governments, despite ceasing their operations and emitting tiny amounts of carbon in a calendar year. Often installations identified by OPIS were not operational at any point during a calendar year but their operators were still handed free allowances that were used to cover the costs of emissions at other plants or were sold on to other emitters for cash.

For example, US fertilizer company CF Industries stopped operations at its Ince ammonia plant in northwest England in September 2021 and the facility was never operational thereafter, while an attempt to sell the facility to a U.K.-based consortium was unsuccessful. At the start of 2022, the company’s UK subsidiary was nonetheless handed 488,602 free UKAs worth approximately £38.68 million ($48.1 million), using average carbon prices for the year.

CF Fertilizers UK Limited Ince Facility Key Data

(Verified emissions data from European Commission and UK government; emission and permit numbers refer to metric tons.)

Looking Ahead to 2024

Under the British government’s proposed changes, an installation operator such as CF Fertilizers UK would have its free allowances retrospectively reassessed. Rather than receiving 488,602 free allowances, the installation would have received 6,754 allowances, reflecting its actual emissions in its last year of operating.

Lawmaker Alex Cunningham, a Member of Parliament in the UK representing the Stockton North constituency, which includes installations that received free allowances despite ceasing operations, cautioned that the current rules remain in place.

“It is outrageous that industrial sites that have shut down production, with a loss of jobs as a result, continue to benefit to the tune of tens of millions [of pounds] from loopholes in the UK Emissions Trading Scheme (ETS), so I’m pleased … that the government have listened and are proposing to put a stop to this practice,” said Cunningham, one of two MPs who tabled questions in Parliament on the subject.

“This is a consultation process, however, and we will see the final recommendations sometime next year. I hope this exercise leads to a real reform of the UK ETS and puts a stop to this shameful profiteering on the back of lost livelihoods,” the Labour MP told OPIS in December.

Loophole in Related EU Emissions Trading System

The UK maintained the same installation cessation rules that it inherited from the EU Emissions Trading System, to which the country belonged until 2021 when the country began operating its own cap-and-trade system. Indeed, most examples identified by OPIS of installation operators benefiting from the loophole took place in the EU, not the UK.

Operators of offline Italian cement plants benefited from the loophole on more occasions over 2013-2020 than installation operators in any other sector across Europe, while the Polish government handed EUAs worth €83 million ($93 million) over 2020 and 2021 to a Krakow-based steel plant and blast furnace operated by ArcelorMittal that was offline after November 2019. Like other companies receiving free EUAs for offline installations, the world’s second-largest steel producer said that it complied with the rules.

The EU already looks set to change its own installation cessation rules. The European Commission’s Expert Group on Climate Change Policy met in June 2023 and discussed a proposal to cap an installation’s designated free allocations starting the day after it is shut down.

Although OPIS has previously reported that more than $400 million of permits have been allocated to the operators of offline plants, the true figure is far higher. In early 2024, OPIS will publish the results of further research regarding other plants, which will show that in the early years of the EU ETS, several governments handed valuable free pollution permits to the operators of offline installations for as long as five years after the plants had stopped operating.

–Reporting by Anthony Lane, alane@opisnet.com and Humberto J. Rocha, hrocha@opisnet.com; Data Investigating by Maryam Naqvi, mnaqvi@opisnet.com; Editing by Michael Kelly, mkelly@opisnet.com

Hear observations from the scene at COP28 on how climate change and the energy transition are transforming companies.

McCloskey analyst James Stevenson, OPIS reporter Humberto J. Rocha and OPIS analyst Denton Cinquegrana delve into key issues including efforts to decarbonize steel production, the development of green hydrogen and the impact of fast-approaching carbon tariffs. View their conversation on OPIS Energy Insights on Barron’s Live.

“Every day has been packed with news, whether it’s talking about carbon capture or decarbonizing the steel or cement industry worldwide. A key takeaway to note is that this event is taking place in a post-inflation reduction act world.” -Humberto J. Rocha

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
implemented.

“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, alane@opisnet.com

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).

What is the CBAM?

To understand the Carbon Border Adjustment Mechanism (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.