Brimex Energy Becomes the First Renewable Natural Gas Project in Mexico Registered on the CleanCounts Registry

This article was originally published by GlobeNewswire on September 3, 2026.

The Jalisco facility, which turns dairy, swine, and tequila-industry waste into clean fuel, is now approved to generate Energy Attribute Certificates on North America’s largest clean energy registry

AGUASCALIENTES, Mexico and WASHINGTON, Sept. 03, 2026 (GLOBE NEWSWIRE) — Brimex EnergyS.A. de C.V. today announced that its renewable natural gas facility in Lagos de Moreno is the first renewable thermal project in Mexico to be registered on the CleanCounts Registry (M-RETS), operated by CleanCounts, the nonprofit that runs North America’s largest clean energy registry. The announcement was made jointly at the Mexico Carbon Forum in Aguascalientes (September 2–3) and at the Renewable Energy Markets conference in Washington, D.C. (September 1–3), placing the news before Mexico’s environmental markets community and the North American clean energy buyers who transact on the registry at the same moment. The registration, completed after an independent third-party engineering review by EcoEngineers found no exceptions, approves Brimex to generate Renewable Thermal Certificates (RTCs), a class of Energy Attribute Certificate (EAC) issued for each dekatherm of verified renewable thermal energy the facility produces.

The Brimex facility converts organic waste from three industries that define the Altos de Jalisco region: dairy, swine production, and tequila. Whey and milk byproducts, swine manure, wastewater sludge, and vinasse from tequila distillation feed three anaerobic digesters on site. This includes material from food and beverage brands including tequila producers Teremana and Campo Azul as well as food brands Grupo Lala and Sigma Alimentos. The resulting biogas powers generators that sell electricity to the commercial grid, and a portion is upgraded into biomethane used as vehicle fuel. Brimex holds Mexico’s first federal permits for the production and, as of February 2026, the commercialization of biomethane. The project’s registry account is held through Cyan Energy S.A. de C.V., which serves as account holder and certificate marketer for the facility.

An EAC is the instrument that lets a buyer prove a clean energy claim. Each certificate carries a unique serial number and records the resource type, location, and production period of one unit of clean energy, creating an auditable chain of custody from generation through retirement. CleanCounts issued its two billionth certificate in 2025, its software issues more than 40% of all renewable energy certificates in North America, and it was the first registry on the continent to track renewable thermal fuels. Its architecture is designed to prevent double counting, the risk that two parties claim the same unit of clean energy.

For Mexico’s emerging biomethane market, registry-grade tracking changes what producers can offer. Certificates give corporate buyers and regulators verifiable documentation of Mexican renewable fuel, recorded on the same infrastructure that utilities and Fortune 500 companies across the United States and Canada already rely on for compliance and sustainability reporting.

“We built this plant to prove that the waste streams of Los Altos, from the dairy barn to the tequila distillery, could provide clean energy to the region,” said Guillermo Chaim Serrano, CEO, Brimex Energy. “Brimex opened Mexico’s biomethane market with the country’s first federal permits, and this registration is the next step. Every dekatherm we produce now carries proof that buyers and auditors across North America recognize.”

“Everyone can see what Brimex built in Lagos de Moreno: the digesters, the upgrading equipment, the fueling station. What no one sees is the infrastructure that makes those molecules count,” said Ben Gerber, President and CEO of CleanCounts. “Registries are the accounting layer of decarbonization. They make sure a dekatherm of Mexican biomethane is measured once, claimed once, and trusted by a buyer or auditor anywhere in North America. Extending that layer to Mexico is a proud moment for our team, and we expect Brimex to be the first of many as clean energy markets grow across Mexico.”

EcoEngineers, the Des Moines-based clean energy consulting and auditing firm acquired by global assurance partner LRQA in March 2025, performed the on-site engineering review of the Brimex facility in April 2025 and serves as the project’s independent reporting entity, delivering verified generation data into the registry.

“A certificate is only as strong as the verification behind it,” said Brad Pleima, P.E., President of EcoEngineers. “Brimex reaching this milestone reflects the rigor and commitment required to establish credible environmental attributes. Our role goes beyond registration, bringing independent technical review, data validation and ongoing audit expertise to help ensure those attributes are supported by a strong, defensible record. We’re proud to support CleanCounts, Brimex, and the Mexican energy market in reaching this important milestone and in the work that continues from here.” 

About Brimex Energy
Brimex Energy S.A. de C.V. is a renewable energy company based in Lagos de Moreno, Jalisco, formed as a joint venture between Grupo Serrano of Mexico and Farmergy of the United Kingdom. Brimex designs, builds, and operates anaerobic digestion and biogas upgrading systems, and holds Mexico’s first federal permits for the production, storage, and commercialization of biomethane. Its Lagos de Moreno facility converts agricultural and agroindustrial waste into biomethane, electricity, and biofertilizer. Learn more at brimexenergy.com.mx.

About CleanCounts
CleanCounts is a nonprofit that operates North America’s largest clean energy registry. For nearly two decades, its market solutions and technology have helped shape clean energy markets and speed the pace of decarbonization. Corporations, regulators, and utilities rely on the CleanCounts Registry (M-RETS) to verify and track the data they need to meet their clean energy obligations and sustainability commitments with confidence. CleanCounts issued its two billionth Energy Attribute Certificate in 2025 and its software issues more than 40 percent of all Renewable Energy Certificates in North America. Learn more at cleancounts.org.

About EcoEngineers
EcoEngineers, an LRQA company, is a consulting, auditing, and advisory firm focused exclusively on the energy transition. Established in 2009 and headquartered in Des Moines, Iowa, with hubs in California, Houston, Europe, and Canada, EcoEngineers helps clients measure emissions, maintain compliance, and make investment decisions grounded in carbon accounting. The firm has modeled and verified hundreds of renewable natural gas projects across North American and European clean fuel programs, and was named Best Verification Company in North America in the 2026 Environmental Market Rankings. Learn more at ecoengineers.us.

Fuel Ethanol Workshop Podcast Series: Live with EcoEngineers

The low-carbon fuel landscape is evolving rapidly, and producers who focus solely on today’s incentives may miss tomorrow’s opportunities. In a recent Ethanol Producer Magazine Podcast recorded live at FEW 2026, EcoEngineers’ Chelsa Oren discussed the growing importance of renewable natural gas (RNG), carbon intensity (CI) modeling, and long-term market readiness.

While the 45Z Clean Fuel Production Credit remains a major consideration for biofuel producers, future low-carbon markets will increasingly reward organizations that understand and actively manage their carbon intensity. Accurate CI modeling can help producers identify opportunities to improve performance, maximize value, and position themselves for emerging regulatory and voluntary market demands.

As new low-carbon programs continue to develop, proactive planning today can create a competitive advantage tomorrow. Producers that invest in data, verification, and strategic carbon management will be better equipped to navigate the next generation of clean fuel markets.

Listen to the full conversation on the Ethanol Producer Magazine Podcast: Watch the podcast

EcoEngineers Approved as Auditor Under the Ammonia Energy Association’s Ammonia Certification System

This article was originally published by GlobeNewswire on August 27, 2026.

New auditing service supports producers, traders, and buyers seeking credible carbon intensity and origin data for low-emission ammonia

EcoEngineers, an LRQA company that provides clean energy auditing and advisory services, today announced that it has been approved as an auditor under the Ammonia Energy Association’s (AEA) Ammonia Certification System, the industry’s global framework for verifying the carbon footprint and origin of low-emission ammonia.

The Ammonia Certification System is a voluntary programme open to producers, traders and consumers across the ammonia value chain. It is supported by a global digital registry that tracks the generation, transfer and retirement of certificates, giving companies a consistent way to document environmental attributes as ammonia moves through the supply chain. The system, officially announced in April 2026, began operating its pilot phase in October 2025 and allows both operating facilities and projects under development to pursue certification.

As an approved auditor, EcoEngineers will support companies at every stage of the ammonia value chain, from early-stage project developers pursuing pre-certification to established producers and traders documenting the carbon footprint of ammonia as it moves through global supply chains. The firm’s team of engineers, scientists, auditors, and consultants brings experience in low-carbon fuel policy and greenhouse gas accounting as well as life-cycle assessments and regulatory guidance to help producers and traders prepare for certification and align with the AEA’s requirements.

According to Tanya Peacock, Managing Director, California and Hydrogen at EcoEngineers:

“Interest in third-party verified ammonia data is increasing. As companies adhere to both voluntary and global policies, they are required to document embedded emissions for market access, and buyers seek chain-of-custody tracking for low-emission ammonia. Downstream customers, such as fertiliser producers and shipping firms, face pressure to verify emissions in their supply chains as they decarbonise. Credible verification is essential.”

Certification under the AEA system provides producers and traders with a harmonised standard that simplifies trade across different regional regulations and relies on independent, third-party verification to support credible claims and reduce the risk of greenwashing. The system also supports pre-certification, allowing project developers to demonstrate the expected environmental attributes of ammonia production before a facility is built.

Trevor Brown, Executive Director, AEA, said:

“The launch of our Ammonia Certification System gives the industry something it hasn’t had before, which is a single, credible way to verify the carbon intensity and origin of ammonia as it moves through the global supply chain. Bringing on approved, independent auditors like EcoEngineers is essential to that credibility. It gives producers, traders and buyers confidence that certifications under our system meet a consistent, rigorous standard, no matter where in the world they’re issued.”

For more information about EcoEngineers’ auditing services under the Ammonia Certification System, contact clientservices@ecoengineers.us.

About EcoEngineers:
EcoEngineers, an LRQA company, is a consulting, auditing and advisory firm exclusively focused on the energy transition and decarbonisation. EcoEngineers helps its clients navigate the disruption caused by carbon emissions and climate change working at the intersection of low-carbon fuel policy, innovative technologies and the carbon marketplace. For more information, visit www.ecoengineers.us.

About the Ammonia Energy Association (AEA):
The AEA was founded in 2004 with a mission to accelerate the responsible adoption of clean ammonia by promoting cross-sectoral collaboration, knowledge sharing, global standards, and supportive policies. This mission supports both the decarbonisation of ammonia production and the use of low-emission ammonia as a fuel and energy carrier. The AEA is a global trade association whose 200+ members represent the full value chain of ammonia across multiple sectors. For more information visit www.ammoniaenergy.org.

2026 SAF Conference Panel Preview Podcast with Kristine Klavers

Sustainable aviation fuel continues to be a focal point in aviation decarbonization discussions. In a recent SAF Magazine podcast, Kristine Klavers, Managing Director of SAF & Renewable Diesel at EcoEngineers, joined host Anna Simet to preview key topics expected to shape conversations at the 2026 SAF Conference & Expo.

Listeners will gain insights into the evolving SAF landscape and hear perspectives on the opportunities and challenges facing the industry as demand for low-carbon aviation solutions continues to grow.

Listen to the full SAF Magazine Podcast.

Biomethane in the Carbon Market: What Operators Need to Know About ETS1 and ETS2

 
Urszula Szalkowska, managing director for European Markets at EcoEngineers, part of LRQA, examines how biomethane is now embedded in the EU’s carbon compliance architecture and what this means in practice for operators under ETS1 and ETS2.

Biomethane has quietly crossed a threshold. It is no longer discussed primarily as a renewable gas alternative to natural gas; it has become a recognised instrument within the EU’s carbon compliance architecture, and the implications for industrial operators, fuel suppliers and gas traders are beginning to materialise in ways that are both financial and operational.

The numbers provide a sense of the scale of what is changing. About 29% of the biomethane used in the European Union (EU) today falls within EU Emissions Trading System 1 (EU ETS 1) sectors, such as power generation and heavy industry, while an additional 43% is used in sectors covered by the newly operational EU Emissions Trading System 2 (ETS2), which includes buildings, road transport and smaller industries.

Together, close to three-quarters of EU biomethane consumption now intersects with the EU ETS in some form. The EU currently produces around 19 billion cubic metres of biomethane, representing roughly 6% of total EU gas consumption. With 90% of EU gas still imported, biomethane is increasingly being positioned by policymakers as both an energy security asset and a strategic substitute for fossil fuels.

This analysis draws on work developed alongside Julian Auderieth, president of the European Renewable Gas Registry (ERGaR), and covers the compliance mechanics, financial value and policy developments that operators in the sector should be tracking.

Under ETS1, the compliance benefit of biomethane flows from a straightforward principle. Operators report total calculated emissions, and where biomethane is used, they must determine the biomass fraction of their fuel mix and demonstrate that it meets the sustainability and GHG savings criteria set out in the Renewable Energy Directive (RED).

When those conditions are satisfied, biomethane can be assigned a zero-emission factor, meaning the emissions associated with its combustion do not require allowances. More eligible biomethane in the fuel mix means a lower fossil fraction, fewer reportable emissions, fewer allowances to surrender and a lower compliance cost. The zero rating is not automatic; it depends on RED compliance and requires the same certification and traceability evidence that underpins proofs of sustainability.

On the operational side, ETS1 also permits a simplified methodology for grid-delivered biogas. Rather than physically tracking individual molecules through the grid, operators can use purchase records of equivalent energy content alongside registry evidence. This is permitted only where the operator can demonstrate that no double counting occurs, that a shared grid connection exists between the producer and the operator, and that compliance with applicable sustainability criteria is achieved. For many ETS installations using grid-sourced biomethane, this flexibility represents a meaningful reduction in administrative burden.

ETS2 introduces a different point of obligation. Rather than sitting with the emitter, compliance costs fall upstream on the fuel supplier releasing fuel for consumption. The same zero-rating principle applies where RED sustainability conditions are met, reducing the total volume of allowances that must be surrendered. One distinction worth noting: ETS is not a life-cycle accounting system, and a negative carbon intensity score for a given biomethane pathway does not reduce ETS compliance emissions below zero. The full life-cycle benefit of high-performing pathways is captured under RED accounting rather than within the ETS framework itself.

The ETS2 timeline is now pressing. The monitoring phase began in 2025, and 2026 is the first full reporting year. By April 2027, regulated entities must submit emissions reports to relevant member state authorities, with the first surrender of allowances due in May 2029. Interest from industrial players and fuel suppliers in using biomethane to manage ETS exposure is rising, but operational readiness across the market remains uneven. Traders generally understand which certificates are needed, yet many face practical challenges with registry interoperability and cross-border transfers. Suppliers may be familiar with monitoring plans in their home markets while lacking the expertise to navigate certificate requirements in the member states where they supply. Some national authorities responsible for verifying ETS compliance are still building familiarity with how biomethane accounting functions in practice.

There is a degree of reassurance in the legal architecture, however. The Monitoring and Reporting Regulation (MRR) is a regulation rather than a directive, which means it is directly binding on all member states without requiring national transposition. Operators who follow what is written in the regulation can reasonably expect national authorities to accept it, and this matters for companies that want to move ahead of the market without waiting for full domestic clarity. Building the right dialogue with local authorities still requires effort, but the legal basis is solid.

The more forward-looking question concerns whether current frameworks are capturing biomethane’s full climate contribution, and at present, they are not. The same biomethane pathway is treated differently depending on which framework applies. Under ETS, biomethane reduces fossil emissions and carbon compliance costs. Under RED, it is assessed on life-cycle performance against a fossil comparator, a more comprehensive methodology that can credit negative carbon intensity scores for high-performing pathways. Under the new Carbon Removal and Carbon Farming Framework (CRCF), where CO2 is captured from a biomethane production process and permanently stored, this constitutes a genuine carbon removal.

This fragmentation creates real costs for producers and investors. A producer investing in carbon capture at a biomethane plant currently faces genuine uncertainty about how that investment will be recognised across all three frameworks. Whether it reduces ETS obligations, generates carbon removal credits under the CRCF or improves a RED certification score depends on different rules, different methodologies and different institutional processes. This complexity raises the cost of investment decisions, particularly at the point where financing commitments need to be made.

The second half of 2026 is shaping up as a material window for change. The post-2030 ETS reform is under active discussion, with the European Commission having opened the conversation about integrating carbon removals into the ETS framework. The Renewable Energy Directive is also heading for revision. Both processes offer a genuine opportunity to reduce fragmentation, allow carbon removals to function as a compliance option within ETS where robust accounting can be assured, and align the treatment of biogenic CO2 across ETS, RED and CRCF using RED as a common regulatory backbone. Getting this right would give the industry clearer signals on value allocation earlier in the investment cycle and reduce the regulatory complexity that producers currently have to navigate across multiple, sometimes conflicting frameworks.

The commercial case for biomethane in industrial decarbonisation is already compelling without further reform. At a recent industry workshop in Ljubljana, an unsubsidised biomethane plant built by AstraZeneca at Gonerby Moor, Lincolnshire, supplying its Cambridge site among others, was presented as a case study. The pharmaceutical company had evaluated two decarbonisation options: green hydrogen at approximately €300 per megawatt-hour, or biomethane at approximately €90 per megawatt-hour, using the same existing infrastructure and equipment. The cost differential reflects a structural advantage that biomethane holds over most alternative pathways – it uses existing gas grid infrastructure, it is a molecule that industry already knows how to handle, and European storage and transport networks are already in place. The ETS is one mechanism that can close the remaining price gap with fossil gas for industrial consumers, and as ETS2 extends carbon pricing to buildings and transport, the same dynamic will apply across a much larger share of the economy.

For operators and suppliers now working through their ETS exposure, several practical issues deserve attention. Monitoring, reporting and verification systems need to correctly handle biomethane accounting – with clear segmentation between ETS1 and ETS2 consumption, robust prevention of double counting, and proper registry and mass-balance documentation. The compliance exposure from weak traceability is real and will grow as ETS2 obligations come fully into force. Separately, the sector continues to need harmonised tracking infrastructure. The EU’s existing certificate instruments were not designed with gaseous energy carriers in mind. Guarantees of Origin were built for the electricity sector, and Proofs of Sustainability were originally developed for liquid biofuels. A fit-for-purpose tracking mechanism for biomethane that functions across borders and registries remains a prerequisite for a well-functioning market, and the ongoing delays to the Union Database (UDB) have created persistent uncertainty that the industry needs to continue pressing to resolve.

On the reform discussions now underway, active engagement from the biomethane industry matters. The current review processes for ETS and RED represent an opportunity to achieve more coherent recognition of biomethane’s full carbon value across frameworks. The European Commission has been receptive to industry input through its call for evidence process, and producers, traders, suppliers and certifiers should be contributing concrete proposals while those discussions remain open.

Renewable Natural Gas: What Investors Should Know

This article was originally published by Environmental Finance.

Ahead of a predicted wave of transactions, Dave Lindenmuth points out some risks and opportunities

The renewable natural gas (RNG) sector is entering a transitional phase. After several years of rapid project development, many developers now face tighter capital markets and shifting demand signals.

For investors and strategic energy asset owners, this moment may represent both risk and opportunity.

Projects that were financed during periods of strong credit prices and robust compliance markets are increasingly seeking recapitalization, portfolio consolidation, or acquisition. As a result, 2026 could see a growing number of RNG assets changing hands.

For infrastructure investors exploring this market, however, evaluating an RNG project requires a nuanced approach. Physical assets are only part of the equation. In reality, the majority of project economics depend on regulatory frameworks, environmental credit markets, feedstocks, and operational compliance systems.

Investors who understand these dynamics are far better positioned to identify high-quality assets and avoid hidden liabilities.

Why RNG investment is entering a new phase

After several years of rapid development, the RNG sector is entering a transitional period.

Historically, most RNG production has been supported by transportation fuel compliance programs such as the Renewable Fuel Standard (RFS) and California’s Low Carbon Fuel Standard (CA-LCFS).

As project development accelerated, supply has begun to outpace demand in these markets, slowing new project investment and leaving some developers seeking recapitalization or strategic buyers.

For investors, this shift could create opportunities. Smaller developers and mid-size operators that built projects during earlier market cycles are increasingly exploring partnerships, portfolio consolidation, or asset sales. As a result, 2026 may see more RNG assets entering the market, creating potential entry points for infrastructure investors with a long-term perspective.

The hidden variable: feedstock risk

Unlike traditional energy assets, RNG facilities depend heavily on upstream feedstock supply, which is mostly waste from other processes. That feedstock may come from dairy manure, landfill gas, or organic waste streams.

While these sources can appear stable on paper, they are influenced by factors outside the facility itself. Changes in agricultural economics, landfill policies, or waste diversion regulations can dramatically affect long-term supply.

Consider a dairy-based RNG project. The facility’s viability depends not only on the digester but also on the financial health of the surrounding dairy industry. If local farms close or consolidate, feedstock supply can disappear quickly.

Similarly, landfill-based projects may face competition from dedicated waste digesters that attract higher-value organic feedstocks. Even regulatory changes affecting landfill diversion can alter gas production volumes over time.

For investors accustomed to evaluating conventional infrastructure assets, these upstream risks are often overlooked.

The downstream market matters just as much

Feedstock risk is only half of the equation. RNG revenue streams are also heavily influenced by downstream regulatory and environmental credit markets.

In many projects, a large share of revenue comes from environmental credits rather than the physical gas itself.

That means investors must evaluate:

  • Eligibility for compliance programs such as the RFS or LCFS.
  • Potential access to emerging markets in Europe or Asia.
  • Future regulatory changes affecting fuel pathways or emissions accounting
  • The structure of offtake and marketing agreements.
  • The timing of credit generation and sales can significantly impact working capital requirements.

Contracts governing credit ownership and compliance responsibilities can significantly affect project value. Poorly structured agreements can create situations where compliance costs outweigh revenue benefits.

Understanding these contractual dynamics is essential when evaluating acquisitions.

Compliance is not a back-office function

Because RNG revenue is tied to environmental credits, compliance systems are central to asset value.

Projects must maintain detailed documentation, operational data, and third-party verification records to generate credits under regulatory programs. In some cases, regulators require data retention for a decade or longer.

For example, agricultural RNG projects may need to retain feedstock documentation such as livestock counts or manure management records for extended periods. If that documentation is incomplete, credit generation, and therefore revenue, can be at risk.

Investors should therefore examine whether project operators maintain:

  • Robust data management systems.
  • Ongoing third-party verification relationships.
  • Established compliance procedures.
  • Clear documentation trails.

A weak compliance program is one of the most significant red flags in RNG due diligence.

Alignment among project partners

Another critical factor is incentive alignment among the various parties involved in a project.

RNG facilities often rely on partnerships between farmers, landfill operators, developers, marketers, and credit aggregators. When incentives are misaligned, operational problems can emerge.

For example, a farmer supplying manure may prioritize farm economics over the needs of the digester facility if their financial incentives are not properly structured. Similarly, marketing partners may pursue strategies that maximize their own returns rather than overall project value.

Projects where stakeholders share aligned incentives and maintain strong working relationships tend to perform far more consistently.

Proven technology, long-term opportunity

RNG remains one of the more mature renewable fuel technologies available today.

The core technology has been deployed successfully for decades, particularly in Europe. Projects generate measurable environmental benefits by capturing methane emissions that would otherwise escape into the atmosphere.

In addition to climate benefits, RNG facilities can improve air quality, reduce odors, and help agricultural operations manage manure and nutrient run-off.

For investors with a long-term infrastructure perspective, these attributes are attractive. Physical assets with proven technology and environmental benefits can remain valuable even through temporary market volatility.

The key question is not whether RNG will remain part of the energy transition. Rather, it is about which investors will successfully identify the projects positioned to perform over the long term.

A market where expertise matters

For financial investors entering the RNG sector, the biggest risk may be assuming that these projects behave like conventional energy infrastructure. They do not.

Feedstock supply chains, regulatory frameworks, compliance systems, and environmental credit markets all shape the economics of RNG assets. Evaluating these factors requires specialized expertise and a comprehensive understanding of the full project value chain.

Investors who approach RNG with that broader perspective will be best positioned to navigate the sector’s next phase of consolidation and capture the opportunities that follow.

Dave Lindenmuth is Senior Director of Growth & Development at EcoEngineers.

How to Hire, Fire, and Get Maximum Value From Carbon Market Consultants

This podcast was originally published by Ross Kenyon for the “Reversing Climate Change” on June 11, 2026.

David LaGreca shares his expertise from countless carbon projects during his time at EcoEngineers and beyond

The Next Phase Of Low-Carbon Fuel Markets

This article was originally published by Ethanol Producer Magazine on June 3, 2026.

BY CHELSA OREN

The ethanol industry has always been adaptive, responding to new policies, market signals and technology pathways. Today, producers are capitalizing on near-term opportunities, such as the 45Z Clean Fuel Production Credit, to capture value and improve margins in a favorable policy environment. But beneath that momentum, a more structural shift is underway, one that could redefine competitiveness in low-carbon fuel markets over the next decade. The message is simple: what earns credits today may earn deficits tomorrow.

A Changing Compliance Curve 
Low-carbon fuel programs, particularly in California, are designed to reduce fuel carbon intensity (CI) over time. The compliance curve, the benchmark that decides whether fuels generate credits or deficits, declines each year, increasing stringency. At present, many ethanol pathways remain comfortably below the 2026 compliance threshold of 24.2% reduction, allowing them to generate credits and support favorable economics. However, recent data indicates that the margin is narrowing. As compliance increases, the stringency aims for a 52.5% reduction by 2035, doubling the reduction planned for 2026. 

CI targets for 2028 and beyond may be accelerated by the Automatic Acceleration Mechanism pursuant to section 95484(b). 

For example, average CI scores for ethanol in Q3 2025 averaged at 58.59  gCO2e/MJ, and by 2035, a CI score above 47.09 gCO2e/MJ for gasoline and 50.23 gCO2e/MJ for diesel curves will result in earning deficits. This is not a distant or hypothetical shift. It is built into the program’s structure and requires a regulation change to modify. As the benchmark declines, fuels that once generated credits will eventually fall below the line, resulting in deficits rather than revenue.

From Credit Generation to Deficit Risk 
This shift will significantly alter market dynamics. Currently, ethanol producers base their strategic choices on existing credit values and logistics. Sometimes, they have withdrawn from markets such as California due to transportation expenses and compliance requirements that outweigh credit earnings. But as the compliance curve tightens, demand will increasingly favor the lowest-CI fuels available. Regulated parties—those responsible for meeting carbon targets—will prioritize ethanol with the lowest possible CI scores to avoid deficit exposure.

This shift establishes a new reality: lower CI ethanol gains increased value, while higher CI ethanol becomes less competitive, yet remains somewhat competitive compared to gasoline. As compliance requirements tighten, credit prices are expected to rise. Essentially, the market will favor early preparers and penalize those who delay.

The Limitations of Short-Term Thinking 
The current focus on 45Z is understandable. It offers immediate financial upside and has become a central part of strategic planning for many producers. However, 45Z alone is not a long-term strategy. Facilities that optimize solely for near-term incentives risk missing the broader trajectory of carbon markets. Investments made today can capture current value while also positioning facilities to meet compliance thresholds over the next five to 10 years. The most competitive producers are already defining long-term CI targets and aligning their operations with those goals.

Pathways to Lower Carbon Intensity 
Lowering CI is not a single decision; it is a portfolio of operational and strategic improvements. Many producers have already taken initial steps, but further reductions will be necessary to remain competitive. Key areas to assess include energy and utilities optimization. Cutting down natural gas and electricity use or switching to lower-carbon energy sources can lead to significant CI reductions. Renewable energy integration through behind-the-meter solutions like renewable natural gas (RNG) or on-site solar can greatly enhance carbon performance. 

Process improvements and efficiency gains, such as converting corn kernel fiber into cellulosic ethanol, can reduce CI while creating additional value streams. Assessing the carbon intensity of inputs, including chemicals and upstream processes, can provide incremental benefits. Although extensively studied, carbon capture and sequestration (CCS) remains a key option where feasible. While these steps may seem incremental individually, collectively they can determine whether a facility remains competitive in a tightening market.

While these strategies are widely understood, the challenge for many producers is not identifying potential improvements but determining where to begin and how to prioritize investments. Each facility operates within unique constraints, including access to feedstocks, energy infrastructure, capital availability and regional market dynamics. As a result, there is no single pathway to achieving lower carbon intensity. Instead, producers must evaluate a combination of options and consider how incremental improvements compound over time.

In many cases, early-stage feasibility assessments can reveal opportunities that are both technically achievable and economically viable, particularly when aligned with future credit market conditions. Engaging with technology providers, utilities and regulatory experts at an early stage can also help clarify timelines and avoid delays later in the process. Importantly, these conversations often uncover dependencies that may not be immediately visible, such as permitting requirements, infrastructure limitations or verification timelines, all of which can influence when a project ultimately delivers value.

Planning Takes Time 
One of the most overlooked challenges in carbon markets is timing. Lowering CI is not an overnight process. It requires feasibility studies, capital investment decisions, technology partnerships, regulatory approvals and operational changes. In some cases, regulatory engagement alone—such as validating new pathways or CI adjustments—can take years. That timeline is precisely why planning must begin now. Producers who wait until the compliance curve becomes restrictive will find themselves reacting under pressure, with fewer options and higher costs.

A Market Signal Producers Can’t Ignore 
The development of low-carbon fuel markets is increasingly understood as a policy certainty as regulatory frameworks continue to evolve and tighten over time. The compliance curve will continue to decline, and the standards for what qualifies as “low-carbon” will become more stringent. Additionally, the market will increasingly differentiate between producers based on their CI performance. With change already underway, the focus is shifting toward how prepared producers are to respond to evolving market conditions.

The Next Phase 
The ethanol industry has consistently demonstrated its ability to innovate and adapt.  
The next phase of that evolution will be defined by how effectively producers manage carbon intensity across both current incentive structures and future compliance requirements. Those who take a long-term view, invest in CI reduction, evaluate new technologies and align with future compliance thresholds will be best positioned to compete. Because in the next phase of low-carbon fuel markets, the advantage will belong to those who planned ahead.

In practice, this means shifting from a reactive approach to a more structured, forward-looking strategy. Producers that establish clear internal benchmarks for carbon intensity, regularly evaluate progress and revisit their assumptions as regulations evolve will be better equipped to navigate uncertainty and capture emerging opportunities in low-carbon fuel markets.

Author: Chelsa Oren, Ethanol and Biodiesel Service Director,  
 EcoEngineers 
       coren@ecoengineers.us

Ongoing Diligence: Chasing Offtake In Carbon Removal Today

This article was originally published by Carbon Herald on April 28, 2026. 

By David LaGreca, managing director of Carbon Markets at EcoEngineers

By the time a carbon dioxide removal (CDR) credit reaches the voluntary carbon market (VCM), it has already passed through an increasingly rigorous set of reviews. Beyond questions of technology or permanence, today’s market puts growing emphasis on how assumptions are tested, data is scrutinized, and projects respond to sustained challenges.

This increased scrutiny is often described as a “quality problem.” In reality, it reflects a maturing market. As buyers, investors, registries, and verifiers apply deeper diligence to minimize risks as much as possible (knowing unknowable risks will always arise), the quality of carbon removal is no longer a static label. It becomes an outcome achieved through process.

The result is a VCM that demands more from projects while providing clearer signals about what credible, investable carbon removal looks like.

From Methodologies to Market Scrutiny

A few years ago, having a credible methodology was often enough to move a project forward. Developers focused on demonstrating that approaches such as bioenergy with carbon capture and storage (BECCS), direct air capture (DAC), or soil carbon mineralization could plausibly remove carbon. Registries validated methodologies, verifiers confirmed conformance, and buyers largely accepted those outcomes.

That era has ended.

Since roughly 2022, trust deficits in the VCM have shifted the center of gravity from registries to buyers. Today, a project may clear registry validation and third-party verification and still fail to secure offtake. Buyers now conduct their own diligence processes or contract with a third-party consultant for diligence, often lasting months, re-examining baseline assumptions, modeling choices, monitoring systems, land-use impacts, governance, and political or reputational risk.

The result is a layered diligence environment in which projects must satisfy multiple stakeholders, each with distinct expectations and incentives.

What Robust Diligence Looks Like in Practice

Despite this fragmentation, a clearer diligence pathway is beginning to emerge. While specifics vary by technology and buyer, high-quality CDR projects increasingly follow a common review sequence that extends beyond registry approval.

  1. Scientific and technical feasibility. This forms the foundation. Projects must demonstrate that their underlying science is credible at a relevant scale and supported by peer-reviewed research or pilot data. Early feasibility assessments help identify red flags before they become costly setbacks. This step is exceptionally important for projects deploying any first-of-its-kind technology, chemistry, or process.
  • Methodology alignment. It’s important that project developers understand that standards and methodologies evolve over time, and that they should aim for the highest attainable bar rather than optimizing for the status quo.
  • Baseline integrity. Whether adapting an existing registry methodology or working within a newer carbon removal standard, projects must show that baselines reflect a credible “no-project” scenario and that crediting assumptions are conservative. Inflated baselines remain one of the fastest ways to lose buyer confidence.
  • Project design and documentation. This translates assumptions into formal plans. Clear, internally consistent documentation that covers system boundaries, monitoring plans, and data management supports validation and reduces friction during downstream reviews.
  • Independent validation and verification. Conducted under International Organization for Standardization (ISO)-aligned requirements, these assessments confirm that projects conform to their chosen methodologies and that claimed removals are supported by evidence. At the same time, verification and credit issuance are no longer tightly coupled to immediate purchase in the voluntary carbon market. Recent market data illustrates the shift: Puro.earth reported that suppliers issued about 650,000 CO₂ Removal Certificates (CORCs) in 2025 while only 344,026 were retired, meaning issuance was roughly 1.9 times retirements for the year. This growing gap reflects a market increasingly driven by forward offtake agreements and future supply reservations rather than spot purchases. Verification therefore remains a critical independent checkpoint for credibility, even as issuance itself no longer guarantees immediate buyer activity.
  • Buyer and investor diligence. Buyers frequently revisit earlier assumptions, interrogate monitoring and reporting systems in greater depth, and evaluate risks ranging from permitting to long-term storage integrity. Projects that have prepared for this scrutiny upstream tend to move through it more efficiently. In other words, project developers should seek out additional scrutiny at the design phase, prior to kicking off the formal registration process with registries.
  • Ongoing monitoring and re-verification. Diligence does not end at first issuance; it must continue over time. Annual or periodic verification and responsiveness to evolving expectations have become defining features of durable projects.

The Stabilizing Role of Verification

One paradox of today’s market is that third-party verification, the only step governed by formal ISO accreditation and independence requirements, is often treated as secondary. Yet verifiers are uniquely positioned to identify structural weaknesses in project design, unrealistic timelines, or gaps in monitoring that can later derail buyer diligence.

When engaged early, verification can function as market preparation rather than a box-checking exercise, helping projects anticipate the questions that will ultimately determine commercial success. Often, issues that arise in verification are sure to arise in diligence.  Major changes to the project during verification are going to spook buyers.  The key is not to rush verification and to de-risk before engagement.

Common Failure Points

Across technologies, several patterns recur when projects struggle to advance. These include overly aggressive timelines that underestimate the duration and cost of diligence; underinvestment in monitoring, particularly digital systems that buyers increasingly expect; reliance on single-track monitoring approaches that fail to satisfy different reviewer preferences; and late engagement with verification experts, which can force redesigns at the worst possible moment.

These are rarely scientific failures. More often, they are process failures and/or misjudgments about how the market now evaluates credibility.

Toward a More Coherent Diligence Ecosystem

If the voluntary carbon market is to scale credibly, diligence must become more predictable without sacrificing rigor. That does not require lowering standards. It requires aligning expectations across registries, verifiers, buyers, and investors so that quality is not re-litigated from scratch at every stage.

For developers, this means treating diligence as a core development activity rather than a downstream compliance task. For buyers, it means recognizing how bespoke requirements shape market participation. For the market, it means acknowledging a simple truth: quality is not a label. It is a process.

About the Author

David LaGreca is the managing director of Carbon Markets Services, EcoEngineers, an LRQAcompany, with experience in all major greenhouse gas (GHG) programs across the Americas. Mr. LaGreca has brought projects through every phase, from conception through financing, methodology development, project registration, and verification. He has worked on hundreds of diverse projects, including reforestation, energy, methane abatement, blue carbon, and novel carbon removal technologies. He has developed and audited GHG inventories for communities, companies, and governments. Mr. LaGreca works to strategically align projects with markets to make decarbonization a viable business

Read more: “We Do A Great Job At Helping People Come To Market With Their Carbon Credits” – Roxby Hartley, PhD, Climate Risk Director At EcoEngineers

Canada’s Clean Fuels Market: What 2025 Clarified And What 2026 Will Test

This article was originally published in Biomass Magazine on March 31, 2026.

By Sally Taylor

For U.S. clean fuel producers looking north, 2025 brought much-needed clarity to Canada’s policy landscape, and 2026 will test how investable that clarity really is. Over the past year, Canadian federal policymakers made a series of targeted adjustments that directly affect cross-border market participants: refining guidance under the Clean Fuel Regulations, proposing focused amendments to address domestic competitiveness, reworking carbon pricing at the consumer level, and introducing time-limited incentives to stabilize Canadian production. Together, these moves reshaped not only the regulatory framework, but also how U.S. producers evaluate risk, return and strategic fit in the Canadian market.

In 2026, the question for U.S. producers is no longer whether Canada is committed to clean fuels; that commitment is clear. The question is how predictable, durable and navigable will the system be for companies accustomed to a very different U.S. policy environment, and how valuable will the market be?

2025: Reducing Friction, Not Raising Ambition 
One of the most critical and often overlooked themes of 2025 was the Canadian government’s effort to reduce friction within the existing policy framework, rather than dramatically expand it. Updated CFR guidance clarified credit creation, verification expectations and reporting mechanics. For many regulated parties, this did not change core compliance obligations, but it did improve confidence where uncertainty had previously slowed investment or delayed market entry. Greater clarity allowed companies to move forward or, just as importantly, reassess projects that no longer aligned with the more straightforward rules.

For U.S. producers, this distinction matters. The Canadian market is often evaluated through a U.S. lens that prioritizes the magnitude of incentives. In 2025, Canada signaled that regulatory certainty and consistency would be the primary value proposition.

The introduction of a new electric vehicle crediting pathway within the CFR fuel life cycle analysis model further reinforced this approach. Rather than positioning electrification as a replacement for liquid and gaseous fuels, Canada is treating transportation decarbonization as a portfolio challenge. For producers exporting renewable fuels into Canada, this signals coexistence.

Sending a Signal Without Rewriting the System 
The Canadian federal government’s decision to pursue targeted CFR amendments rather than a wholesale rewrite is instructive, particularly for foreign producers assessing long-term exposure. Rather than reopening the entire regulatory structure, policymakers focused on specific pressure points: domestic competitiveness, supply resilience and insulation from international policy volatility.

Proposals such as domestic content considerations and potential credit multipliers were framed less as protectionist measures and more as stabilization tools designed to preserve Canadian production capacity.

For U.S. RNG developers and other clean fuel producers, this approach introduces both opportunity and complexity. It creates optionality for projects aligned with Canadian priorities, while also underscoring the importance of understanding policy intent, not just regulatory language. The Canadian system rewards alignment and durability over short-term arbitrage.

Reflecting Global Realities, Not a Philosophy Shift 
The announcement of a time-limited biofuel production incentive, supporting Canadian biodiesel and renewable diesel producers through 2026 and 2027, represented the clearest acknowledgment of global market dynamics. This incentive isn’t meant to fundamentally change the Canadian market or replicate the U.S.-style subsidies forever. Instead, it recognizes that Canada’s clean fuels industry is part of a closely linked North American system, where shifts in U.S. federal incentives can swiftly impact the competitive landscape. 

For U.S. producers evaluating exports or partnerships in Canada, the message is nuanced: incentives may appear smaller or more targeted, but they are deployed strategically. The incentive functions as a bridge, not a destination, thus buying time for domestic supply while preserving long-term regulatory integrity.

Carbon Pricing Rebalanced, Not Abandoned 
The removal of the consumer carbon tax in 2025 drew significant attention, particularly from outside Canada. Its implications for clean fuels, however, are often misunderstood. While consumer-facing carbon pricing was eliminated, industrial carbon pricing through the Output-Based Pricing System remained intact. For clean fuel producers and compliance entities, this distinction is critical. The OBPS continues to anchor carbon value within the industrial economy, preserving a meaningful price signal for emissions reductions without placing direct costs on households.

For U.S. producers accustomed to more volatile or incentive-driven carbon markets, this represents a different kind of stability—one grounded in industrial compliance rather than consumer behavior.

What 2026 Will Test 
As Canada enters 2026, its clean fuels framework moves into a new phase. The rules are largely in place. Guidance has improved. Amendments are under consideration. Incentives are defined, if temporary. The year ahead will test execution, integration and strategic discipline, particularly for companies operating across borders.

Author: Sally Taylor   
Director of Strategic Development, EcoEngineers